NRG Energy (NRG) 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013
Document And Entity Information [Abstract]	'	'
Entity Registrant Name	'NRG ENERGY, INC.	'
Entity Central Index Key	'0001013871	'
Document Type	'10-K	'
Document Period End Date	31-Dec-13	'
Amendment Flag	'false	'
Current Fiscal Year End Date	'--12-31	'
Entity Well-known Seasoned Issuer	'Yes	'
Entity Voluntary Filers	'No	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Public Float	'	$7,506,455,756
Entity Common Stock, Shares Outstanding	325,217,179	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'FY	'

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues	'	'	'	'	'	'	'	'	'	'	'
Total operating revenues	$2,795	$3,490	$2,930	$2,081	$2,063	$2,331	$2,166	$1,862	$11,295	$8,422	$9,079
Operating Costs and Expenses	'	'	'	'	'	'	'	'	'	'	'
Cost of operations	'	'	'	'	'	'	'	'	8,121	6,140	6,745
Depreciation and amortization	'	'	'	'	'	'	'	'	1,256	950	896
Impairment losses	'	'	'	'	'	'	'	'	459	0	160
Selling, general and administrative	'	'	'	'	'	'	'	'	904	807	586
Acquisition-related transaction and integration costs	'	'	'	'	'	'	'	'	128	107	0
Development activity expenses	'	'	'	'	'	'	'	'	84	68	57
Total operating costs and expenses	'	'	'	'	'	'	'	'	10,952	8,072	8,444
Operating Income	-205	527	287	-266	37	86	397	-170	343	350	635
Other Income/(Expense)	'	'	'	'	'	'	'	'	'	'	'
Equity in earnings of unconsolidated affiliates	'	'	'	'	'	'	'	'	7	37	35
Bargain purchase gain related to GenOn acquisition	'	'	'	'	'	'	'	'	0	296	0
Impairment losses on investments	'	'	'	'	'	'	'	'	-99	-2	-495
Other income, net	'	'	'	'	'	'	'	'	13	19	19
Loss on debt extinguishment	'	'	'	'	'	'	'	'	-50	-51	-175
Interest expense	'	'	'	'	'	'	'	'	-848	-661	-665
Total other expense	'	'	'	'	'	'	'	'	-977	-362	-1,281
(Loss)/Income Before Income Taxes	'	'	'	'	'	'	'	'	-634	-12	-646
Income tax benefit	'	'	'	'	'	'	'	'	-282	-327	-843
Net (Loss)/Income	'	'	'	'	'	'	'	'	-352	315	197
Less: Net income attributable to noncontrolling interest	'	'	'	'	'	'	'	'	34	20	0
Comprehensive (Income) Loss, Net of Tax, Attributable to Noncontrolling Interest	'	'	'	'	'	'	'	'	34	20	0
Net (Loss)/Income Attributable to NRG Energy, Inc.	-290	116	122	-334	252	-1	251	-207	-386	295	197
Dividends for preferred shares	'	'	'	'	'	'	'	'	9	9	9
(Loss)/Income Available for Common Stockholders	'	'	'	'	'	'	'	'	($395)	$286	$188
(Loss)/Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders	'	'	'	'	'	'	'	'	'	'	'
Weighted average number of common shares outstanding - basic (in shares)	323	323	323	323	247	228	228	228	323	232	240
Net Income/(Loss) per Weighted Average Common Share - Basic (in dollars per share)	($0.90)	$0.36	$0.38	($1.03)	$1.02	($0.01)	$1.09	($0.92)	($1.22)	$1.23	$0.78
Weighted average number of common shares outstanding - diluted (in shares)	323	327	327	323	249	228	229	228	323	234	241
Net Income/(Loss) Per Weighted Average Common Share - Diluted (in dollars per share)	($0.90)	$0.35	$0.37	($1.03)	$1.01	($0.01)	$1.08	($0.92)	($1.22)	$1.22	$0.78
Dividends Per Common Share	'	'	'	'	'	'	'	'	$0.45	$0.18	$0

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net (Loss)/Income	($352)	$315	$197
Other Comprehensive Income/(Loss), net of tax	'	'	'
Unrealized gain/(loss) on derivatives, net of income tax benefit of $6, $94, and $181	8	-163	-309
Foreign currency translation adjustments, net of income tax benefit of $14, $1, and $1	-24	-1	-2
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax benefit of $0, $6, and $0	0	-11	0
Available-for-sale securities, net of income tax expense of $2, $1, and $0	3	3	-1
Defined benefit plan, net of income tax (expense)/benefit of $(100), $21, and $27	168	-52	-46
Other comprehensive income/(loss)	155	-224	-358
Comprehensive Income/(Loss)	-197	91	-161
Less: Comprehensive income attributable to noncontrolling interest	-34	-20	0
Less: Net income attributable to noncontrolling interest	34	20	0
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	-231	71	-161
Dividends for preferred shares	9	9	9
Comprehensive Income/(Loss) Available for Common Stockholders	($240)	$62	($170)

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrealized loss/gain on derivatives, income tax benefit/(expense)	($6)	($94)	($181)
Foreign currency translation adjustments, income tax benefit/(expense)	-14	-1	-1
Reclassification adjustment for translation gain realized upon sale of Schkopau, income tax benefit/(expense)	0	-6	0
Available-for-sale securities, income tax benefit/(expense)	-2	-1	0
Defined benefit plan, income tax benefit/(expense)	$100	($21)	($27)

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current Assets	'	'
Cash and cash equivalents	$2,254	$2,087
Funds deposited by counterparties	63	271
Restricted cash	268	217
Accounts receivable — trade, less allowance for doubtful accounts of $40 and $32	1,214	1,061
Inventory	898	903
Derivative instruments	1,328	2,644
Cash collateral paid in support of energy risk management activities	276	229
Deferred income taxes	258	56
Renewable energy grant receivable	539	58
Prepayments and other current assets	498	446
Total current assets	7,596	7,972
Property, Plant and Equipment	'	'
In service	23,649	21,133
Under construction	2,775	4,428
Total property, plant and equipment	26,424	25,561
Less accumulated depreciation	-6,573	-5,408
Net property, plant and equipment	19,851	20,153
Other Assets	'	'
Equity investments in affiliates	453	676
Notes receivable, less current portion	73	79
Goodwill	1,985	1,956
Intangible assets, net of accumulated amortization of $1,977 and $1,706	1,140	1,210
Nuclear decommissioning trust fund	551	473
Derivative instruments	311	662
Deferred income taxes	1,202	1,203
Other non-current assets	740	599
Total other assets	6,455	6,858
Total Assets	33,902	34,983
Current Liabilities	'	'
Current portion of long-term debt and capital leases	1,050	147
Accounts payable	1,038	1,172
Derivative instruments	1,055	1,981
Cash collateral received in support of energy risk management activities	63	271
Accrued interest expense	185	191
Other accrued expenses	480	539
Accounts Payable and Other Accrued Liabilities	998	'
Other current liabilities	333	369
Total current liabilities	4,204	4,670
Other Liabilities	'	'
Long-term debt and capital leases	15,767	15,736
Nuclear decommissioning reserve	294	354
Nuclear decommissioning trust liability	324	273
Postretirement and other benefit obligations	506	803
Deferred income taxes	22	55
Derivative instruments	195	500
Out-of-market contracts	1,177	1,278
Other non-current liabilities	695	796
Total non-current liabilities	18,980	19,795
Total Liabilities	23,184	24,465
3.625% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs)	249	249
Commitments and Contingencies	'	'
Stockholders' Equity	'	'
Common stock; $0.01 par value; 500,000,000 shares authorized; 401,126,780 and 399,112,616 shares issued and 323,779,252 and 322,606,898 shares outstanding at December 31, 2013 and 2012	4	4
Additional paid-in capital	7,840	7,587
Retained earnings	3,695	4,230
Less treasury stock, at cost; 77,347,528 and 76,505,718 shares at December 31, 2013 and 2012	-1,942	-1,920
Accumulated other comprehensive income/(loss)	5	-150
Noncontrolling interest	867	518
Total Stockholders' Equity	10,469	10,269
Total Liabilities and Stockholders' Equity	$33,902	$34,983

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Accounts receivable - trade, allowance for doubtful accounts (in millions)	$40,000,000	$32,000,000
Intangible assets, accumulated amortization (in millions)	1,977,000,000	1,706,000,000
3.625% convertible perpetual preferred stock, interest rate (as a percent)	3.63%	3.63%
3.625% convertible perpetual preferred stock, par value (in dollars)	$0.01	$0.01
3.625% convertible perpetual preferred stock, shares issued	250,000	250,000
3.625% convertible perpetual preferred stock, shares outstanding	250,000	250,000
3.625% convertible perpetual preferred stock, liquidation value (in dollars)	$250	$250
Common stock, par value (in dollars)	$0.01	$0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	401,126,780	399,112,616
Common stock, shares outstanding	323,779,252	322,606,898
Treasury stock, shares	77,347,528	76,505,718

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows from Operating Activities	'	'	'
Net (Loss)/Income	($352)	$315	$197
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:	'	'	'
Distributions and equity in earnings of unconsolidated affiliates	84	2	9
Bargain purchase gain related to GenOn acquisition	0	-296	0
Depreciation and amortization	1,256	950	896
Provision for bad debts	67	45	59
Amortization of nuclear fuel	36	39	39
Amortization of financing costs and debt discount/premiums	-33	-31	-32
Adjustment to loss on debt extinguishment	-15	9	58
Amortization of intangibles and out-of-market contracts	49	146	167
Amortization of unearned equity compensation	38	41	28
(Gain)/Loss on disposals and sales of assets, net	-3	11	14
Impairment losses	558	0	657
Changes in derivative instruments	164	124	-138
Changes in deferred income taxes and liability for uncertain tax benefits	-67	-353	-859
Changes in nuclear decommissioning trust liability	15	37	20
Cash (used)/provided by changes in other working capital, net of acquisition and disposition effects:	'	'	'
Accounts receivable - trade	224	131	119
Inventory	-11	172	-145
Prepayments and other current assets	22	26	-59
Accounts payable	275	-132	9
Accrued expenses and other current liabilities	-114	231	-111
Other assets and liabilities	453	-278	-4
Net Cash Provided by Operating Activities	1,270	1,149	1,166
Cash Flows from Investing Activities	'	'	'
Acquisition of businesses, net of cash acquired	-494	-81	-377
Cash acquired in GenOn acquisition	0	983	0
Capital expenditures	-1,987	-3,396	-2,310
Increase in restricted cash, net	-22	-66	-35
(Increase)/decrease in restricted cash to support equity requirements for U.S. DOE funded projects	-26	164	-215
(Increase)/decrease in notes receivable	-11	-24	12
Proceeds from renewable energy grants	55	62	0
Purchases of emission allowances, net of proceeds	5	1	19
Investments in nuclear decommissioning trust fund securities	-514	-436	-406
Proceeds from sales of nuclear decommissioning trust fund securities	488	399	385
Proceeds from sale of assets, net	13	137	7
Investments in unconsolidated affiliates	0	-25	-66
Other	-35	22	-23
Net Cash Used by Investing Activities	-2,528	-2,262	-3,047
Cash Flows from Financing Activities	'	'	'
Payment of dividends to preferred and common stockholders	-154	-50	-9
Net receipts/(payments for) from settlement of acquired derivatives that include financing elements	267	-68	-83
Payment for treasury stock	-25	0	-430
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	531	347	29
Proceeds from issuance of common stock	16	0	2
Proceeds from issuance of long-term debt	1,777	3,165	6,224
Payments for term loan for funded letter of credit facility	0	0	-1,300
Decrease in restricted cash supporting funded letter of credit facility	0	0	1,300
Payment of debt issuance and hedging costs	-50	-35	-207
Payments for short and long-term debt	-935	-1,260	-5,493
Net Cash Provided by Financing Activities	1,427	2,099	33
Effect of exchange rate changes on cash and cash equivalents	-2	-4	2
Net Increase/(Decrease) in Cash and Cash Equivalents	167	982	-1,846
Cash and Cash Equivalents at Beginning of Period	2,087	1,105	2,951
Cash and Cash Equivalents at End of Period	$2,254	$2,087	$1,105

Consolidated_Statement_of_Stoc

Consolidated Statement of Stockholders' Equity (USD $)	Total	Preferred Stock	Common Stock	Additional Paid-In Capital	Retained Earnings	Treasury Stock	Accumulated Other Comprehensive Income/(Loss)	Noncontrolling Interest	NRG Yield
In Millions, unless otherwise specified
Balance at Dec. 31, 2010	$8,072	$0	$3	$5,323	$3,800	($1,503)	$432	$17	'
Increase (Decrease) in Stockholders' Equity	'	'	'	'	'	'	'	'	'
Net income/(loss) attributable to NRG Energy, Inc.	197	'	'	'	197	'	'	'	'
Net income/(loss) attributable to noncontrolling interest	0	'	'	'	'	'	'	0	'
Net (Loss)/Income	197	'	'	'	'	'	'	'	'
Other comprehensive loss	-358	'	'	'	'	'	-358	'	'
Equity-based compensation	28	'	'	28	'	'	'	'	'
Purchase of treasury stock	-430	'	'	'	'	-430	'	'	'
Preferred stock dividends	-9	'	'	'	-9	'	'	'	'
ESPP share purchases	3	'	'	-5	-1	9	'	'	'
Proceeds from issuance of common stock	2	'	'	'	'	'	'	'	'
NINA deconsolidation	-17	'	'	'	'	'	'	-17	'
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	183	'	'	'	'	'	'	183	'
Balance at Dec. 31, 2011	7,669	0	3	5,346	3,987	-1,924	74	183	'
Increase (Decrease) in Stockholders' Equity	'	'	'	'	'	'	'	'	'
Net income/(loss) attributable to NRG Energy, Inc.	295	'	'	'	'	'	'	'	'
Net income/(loss) attributable to noncontrolling interest	20	'	'	'	'	'	'	20	'
Net (Loss)/Income	315	'	'	'	'	'	'	'	'
Other comprehensive loss	-224	'	'	'	'	'	-224	'	'
Issuance of shares for acquisition of GenOn	2,177	'	1	2,176	'	'	'	'	'
Equity-based compensation	34	'	'	34	'	'	'	'	'
Preferred stock dividends	-9	'	'	'	-9	'	'	'	'
Common stock dividends	-41	'	'	'	-41	'	'	'	'
ESPP share purchases	1	'	'	-1	-2	4	'	'	'
Proceeds from issuance of common stock	0	'	'	'	'	'	'	'	'
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	'	'	'	'	'	'	'	315	'
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	'	'	'	32	'	'	'	'	'
Noncontrolling Interest Increase From Contributions From Noncontrolling Interest Holders	347	'	'	'	'	'	'	'	'
Balance at Dec. 31, 2012	10,269	0	4	7,587	4,230	-1,920	-150	518	'
Increase (Decrease) in Stockholders' Equity	'	'	'	'	'	'	'	'	'
Net income/(loss) attributable to NRG Energy, Inc.	-386	'	'	'	-386	'	'	'	'
Net income/(loss) attributable to noncontrolling interest	34	'	'	'	'	'	'	34	'
Net (Loss)/Income	-352	'	'	'	'	'	'	'	'
Other comprehensive loss	155	'	'	'	'	'	155	'	'
Equity-based compensation	36	'	'	36	'	'	'	'	'
Purchase of treasury stock	-25	'	'	'	'	-25	'	'	'
Preferred stock dividends	-9	'	'	'	-9	'	'	'	'
Common stock dividends	-145	'	'	'	-145	'	'	'	'
ESPP share purchases	8	'	'	'	5	3	'	'	'
Proceeds from issuance of common stock	16	'	'	217	'	'	'	240	457
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	'	'	'	'	'	'	'	75	'
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	'	'	'	'	'	'	'	'	'
Noncontrolling Interest Increase From Contributions From Noncontrolling Interest Holders	75	'	'	'	'	'	'	'	'
Balance at Dec. 31, 2013	$10,469	$0	$4	$7,840	$3,695	($1,942)	$5	$867	'

Nature_of_Business

Nature of Business	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Nature of Business	'
	Nature of Business
	General
	NRG Energy, Inc., or NRG or the Company, is a competitive power and energy company that aspires to be a leader in the way residential, industrial and commercial consumers think about, use, produce and deliver energy and energy services in major competitive power markets in the United States. NRG engages in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; the transacting in and trading of fuel and transportation services and the direct sale of energy, services, and innovative, sustainable products to retail customers. The Company sells retail electric products and services under the name “NRG” and various brands owned by NRG. Finally, NRG aspires to be a clean energy leader and is focused on the deployment and commercialization of potentially transformative technologies, like electric vehicles, Distributed Solar and smart meter/home automation technology that collectively have the potential to fundamentally change the nature of the power industry, including a substantial change in the role of the national electric transmission grid and distribution system.
	NRG's domestic generation facilities consist of intermittent, baseload, intermediate, and peaking power generation facilities. The following table summarizes NRG's global generation portfolio by operating segment, which includes 88 fossil fuel and nuclear plants, eleven Utility Scale Solar facilities and four wind farms, as well as Distributed Solar facilities. Also included is one Utility Scale Solar facility and additional Distributed Solar facilities currently under construction. All Utility Scale Solar and Distributed Solar facilities are described in megawatts on an alternating current basis. MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units:
		Fossil Fuel, Nuclear, and Renewable
		(In MW)
	Generation Type	Texas	East	South Central	West	Alternative Energy		NRG Yield		Total Domestic		Other (Inter-national)	Total Global
	Natural gas	5,917	7,651	3,817	6,779	—		843		25,007		—	25,007
	Coal	4,193	6,879	1,496	—	—		—		12,568		605	13,173
	Oil(a)	—	5,531	—	—	—		190		5,721		—	5,721
	Nuclear	1,176	—	—	—	—		—		1,176		—	1,176
	Wind	—	—	—	—	347		101		448		—	448
	Utility Scale Solar	—	—	—	—	836		303		1,139		—	1,139
	Distributed Solar	—	—	—	—	37		10		47		—	47
	Total generation capacity	11,286	20,061	5,313	6,779	1,220		1,447		46,106		605	46,711
	Capacity attributable to noncontrolling interest	—	—	—	—	(331	)	(499	)	(830	)	—	(830	)
	Total net generation capacity	11,286	20,061	5,313	6,779	889		948		45,276		605	45,881
	Under Construction
	Utility Scale Solar	—	—	—	—	26		—		26		—	26
	Distributed Solar	—	—	—	—	6		—		6		—	6
	Total under construction	—	—	—	—	32		—		32		—	32
	(a) The NRG Yield operating segment consists of two dual-fuel (natural gas and oil) simple-cycle generation facilities.
	In addition, the Company's thermal assets provide steam and chilled water capacity of approximately 1,374 MWt through its district energy business, 28 MWt of which is available under the right-to-use provision of the Chilled Water Service Agreement at NRG Energy Center Phoenix, AZ.
	NRG sells power from its generation portfolio, offers capacity or similar products to retail electric providers and others, and provides ancillary services to support system reliability.
	The Retail Business provides energy and related services to residential, commercial and institutional customers primarily located in Texas and selected Northeast markets. Products and services range from system power to home services, to bundled products which combine system power with protection products, energy efficiency and renewable energy solutions. Based on metered locations, as of December 31, 2013, NRG's Retail Business served approximately 2.3 million residential, small business, commercial and industrial customers.
	NRG was incorporated as a Delaware corporation on May 29, 1992. NRG's common stock is listed on the New York Stock Exchange under the symbol "NRG". The Company's principal executive offices are located at 211 Carnegie Center, Princeton, New Jersey 08540. NRG is dual headquartered, with financial and commercial headquarters in Princeton, New Jersey and operational headquarters in Houston, Texas. NRG's telephone number is (609) 524-4500. The address of the Company's website is www.nrgenergy.com. NRG's recent annual reports, quarterly reports, current reports, and other periodic filings are available free of charge through the Company's website.
	Initial Public Offering of NRG Yield, Inc.
	The Company formed NRG Yield, Inc. to own and operate a portfolio of contracted generation assets and thermal infrastructure assets that have historically been owned and/or operated by NRG and its subsidiaries. On July 22, 2013, NRG Yield, Inc. closed its initial public offering of 22,511,250 shares of Class A common stock at a price of $22 per share. Net proceeds to NRG Yield, Inc. from the sale of the Class A common stock were approximately $468 million, net of underwriting discounts and commissions of $27 million. The Company retained 42,738,250 shares of Class B common stock of NRG Yield, Inc. As a result, the Company owns a controlling interest in NRG Yield, Inc. and will consolidate this entity for financial reporting purposes. In addition, the Company retained a 65.5% interest in NRG Yield LLC. The initial public offering represented the sale of a 34.5% interest in NRG Yield LLC. NRG Yield LLC's initial assets consisted of three natural gas or dual-fired facilities, eight utility-scale solar and wind generation facilities, two portfolios of distributed solar facilities that collectively represent 1,324 net MW, and thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,098 net MWt and electric generation capacity of 123 net MW. On December 31, 2013, NRG Yield LLC acquired Energy Systems, as described in Note 3, Business Acquisitions and Dispositions. The following table represents the structure of NRG Yield, Inc. after the initial public offering:

Summary_of_Significant_Account

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	Basis of Presentation and Principles of Consolidation
	The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
	The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE should be consolidated.
	Segment Reporting
	Effective June 2013, the Company's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are primarily segregated based on the Retail Business, conventional power generation, alternative energy businesses, NRG Yield, and corporate activities.  Within NRG's conventional power generation, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, East, South Central, West and Other, which includes international businesses and maintenance services.  The Company's alternative energy segment includes solar and wind assets, excluding those in the NRG Yield segment, electric vehicle services and the carbon capture business.  NRG Yield includes certain of the Company's contracted generation assets including three natural gas or dual-fired facilities, eight utility-scale solar and wind generation facilities, two portfolios of distributed solar facilities and thermal infrastructure assets.
	Cash and Cash Equivalents
	Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
	Funds Deposited by Counterparties
	Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some 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 general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge 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. Changes in funds deposited by counterparties are closely associated with the Company's operating activities, and are classified as an operating activity in the Company's consolidated statements of cash flows.
	Restricted Cash
	Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments as well as to fund required equity contributions, per the restrictions of the debt agreements.
	Trade Receivables and Allowance for Doubtful Accounts
	Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its Retail Business, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. The Retail Business writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.
	Inventory
	Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at a weighted average cost, since the Company expects to recover these costs in the ordinary course of business. The Company removes these inventories when they are used for repairs, maintenance or capital projects. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
	Property, Plant and Equipment
	Property, plant and equipment are stated at cost; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation other than nuclear fuel is computed using the straight-line method, while nuclear fuel is amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.
	Asset Impairments
	Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets and present value techniques.
	Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value.
	For further discussion of these matters, refer to Note 10, Asset Impairments.
	Development Activity Expenses and Capitalized Interest
	Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset.
	Development activity expenses include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
	Development activity expenses also include selling, general, and administrative expenses associated with the current operations of certain developing businesses including residential solar, electric vehicles, waste-to-energy, carbon capture and other emerging technologies. The revenue associated with these businesses was immaterial for the years ended December 31, 2013, 2012, and 2011. When it is determined that a business will remain an ongoing part of the Company's operations or when operating revenues become material relative to the operating costs of the underlying business, the Company no longer classifies a business as a development activity.
	Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2013, 2012, and 2011, was $64 million, $104 million, and $80 million, respectively.
	When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
	Debt Issuance Costs
	Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt.
	Intangible Assets
	Intangible assets represent contractual rights held by NRG. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, development rights, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, NRG also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis.
	Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. NRG had no intangible assets with indefinite lives recorded as of December 31, 2013.
	Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.
	Goodwill
	In accordance with ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable.
	In September 2011, the FASB issued ASU No. 2011-08, Intangibles - Goodwill and Other (Topic 350) Testing Goodwill for Impairment, or ASU No. 2011-08. The objective of ASU 2011-08 is to simplify how entities test goodwill for impairment. The amendments in ASU No. 2011-08 permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. The Company adopted the provisions of ASU No. 2011-08, effective January 1, 2011, with no impact on its results of operations, financial position or cash flows.
	In the absence of sufficient qualitative factors, goodwill impairment is determined using a two step process:
		Step one —	Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two.
		Step two —	Compare the implied fair value of the reporting unit's goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds fair value, an impairment charge is recognized for the sum of such excess.
	Income Taxes
	NRG accounts for income taxes using the liability method in accordance with ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
	NRG has two categories of income tax expense or benefit — current and deferred, as follows:
	•	Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and
	•	Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income.
	NRG reports some of the Company's revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. NRG measures the Company's deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in our estimate of future taxable income, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized.
	NRG reduces its current income tax expense in the consolidated statement of operations for any investment tax credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently amortized to earnings on a straight-line basis over the useful life of each underlying property.
	The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.
	In accordance with ASC 805 and as discussed further in Note 19, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.
	Revenue Recognition
	Energy — Both physical and financial transactions are entered into to optimize the financial performance of NRG's generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.
	Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.
	Sale of Emission Allowances — NRG records the Company's bank of emission allowances as part of the Company's intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. NRG records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.
	Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes.
	Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $166 million, $151 million and $186 million for the years ended December 31, 2013, 2012, and 2011, respectively. These revenues represent the sale of excess supply to third parties in the market.
	Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. NRG recorded receivables for unbilled revenues of $356 million, $338 million and $318 million as of December 31, 2013, 2012, and 2011, respectively, for retail energy sales and services.
	PPAs — Certain of the Company's revenues are currently obtained through PPAs or other contractual arrangements. All of these PPAs are recorded as operating leases in accordance with ASC 840, Leases, or ASC 840. ASC 840 requires minimum lease payments received to be amortized over the term of the lease and contingent rentals are recorded when the achievement of the contingency becomes probable. These leases have no minimum lease payments and all the rent is recorded as contingent rent on an actual basis when the electricity is delivered. The contingent rental income recognized in the years ended December 31, 2013, 2012, and 2011 was $400 million, $130 million, and $27 million, respectively.
	Gross Receipts and Sales Taxes
	In connection with its Retail Business, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2013, 2012, and 2011, NRG's revenues and cost of operations included gross receipts taxes of $88 million, $79 million, and $78 million respectively. Additionally, the Retail Business records sales taxes collected from its taxable customers and remitted to the various governmental entities on a net basis, thus, there is no impact on the Company's consolidated statement of operations.
	Cost of Energy for Retail Operations
	The cost of energy for electricity sales and services to retail customers is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ($90 million, $97 million and $87 million as of December 31, 2013, 2012, and 2011, respectively) was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.
	Derivative Financial Instruments
	NRG accounts for derivative financial instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges, if elected for hedge accounting, are either:
•	Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or
•	Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings.
NRG's primary derivative instruments are power sales contracts, fuels purchase contracts, other energy related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, NRG assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Hedge accounting will also be discontinued on contracts related to commodity price risk previously accounted for as cash flow hedges when it is probable that delivery will not be made against these contracts. In this case, the gain or loss previously deferred in accumulated OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until the underlying hedged item is delivered.
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
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.
Foreign Currency Translation and Transaction Gains and Losses
The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's statements of operations. For the years ended December 31, 2013, 2012, and 2011, amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2013, 2012, and 2011 were $15 million, $53 million and $72 million, respectively.
Concentrations of Credit Risk
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 4, Fair Value of Financial Instruments, for a further discussion of derivative concentrations.
Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payables, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 4, Fair Value of Financial Instruments for a further discussion of fair value of financial instruments.
Asset Retirement Obligations
NRG accounts for its AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, NRG capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 13, Asset Retirement Obligations, for a further discussion of AROs.
Pensions and Other Postretirement Benefits
NRG offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. NRG accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. NRG recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of NRG's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. NRG's actuarial consultants determine assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.
NRG measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820.
Stock-Based Compensation
NRG accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718. The fair value of the Company's non-qualified stock options and performance units are estimated on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of NRG's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award.
Investments Accounted for by the Equity Method
NRG has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NRG from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates.
Marketing and Advertising Costs
The Company expenses its advertising and marketing costs as incurred. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Marketing and advertising expenses included within selling, general and administrative expense for the years ended December 31, 2013, 2012, and 2011 were $195 million, $197 million, and $127 million respectively.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
In recording transactions and balances resulting from business operations, NRG uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, and the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications
Certain prior-year amounts have been reclassified for comparative purposes.
Recent Accounting Developments
ASU 2011-11 - Effective January 1, 2013, the Company adopted the provisions of ASU No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities, or ASU No. 2011-11, and began providing enhanced disclosures regarding the effect or potential effect of netting arrangements on an entity's financial position by improving information about financial instruments and derivative instruments that either (1) offset in accordance with either ASC 210-20-45 or ASC 810-20-45 or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. Reporting entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The disclosures required by ASU No. 2011-11 are required to be adopted retroactively. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.
ASU 2013-02 - Effective January 1, 2013, the Company adopted the provisions of ASU No. 2013-02, Other Comprehensive Income (Topic 220) Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, or ASU No. 2013-02, and began reporting the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income within the notes to the financial statements if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income in the same reporting period. For other amounts not required by U.S. GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures which provide additional information about the amounts.  The provisions of ASU No. 2013-02 are required to be adopted prospectively.  As this guidance provides only presentation requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.
Other - The following accounting standard was issued in 2013 and was adopted January 1, 2014:
•ASU 2013-11 - In July 2013, the FASB issued ASU No. 2013-11, Income Taxes (Topic 740) Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, or ASU No. 2013-11.  The amendments of ASU 2013-11 requires an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, as a reduction of a deferred tax asset for a net operating loss, or NOL, a similar tax loss or tax credit carryforwards rather than a liability when the uncertain tax position would reduce the NOL or other carryforward under the tax law of the applicable jurisdiction and the entity intends to use the deferred tax asset for that purpose.  The guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 with early adoption permitted. The Company adopted this standard effective December 31, 2013. The adoption of this standard did not impact the Company's results of operations or cash flows as the unrecognized tax benefits relate to state issues and the Company either has no NOL's or the NOL's are limited for that particular jurisdiction.

Business_Acquisitions_and_Disp

Business Acquisitions and Dispositions (Notes)	12 Months Ended
	Dec. 31, 2013
Business Acquisitions and Dispositions [Abstract]	'
Business Acquisitions and Dispositions	'
	Business Acquisitions and Dispositions
	2013 Acquisitions
	Pending Acquisition — On October 18, 2013, the Company entered into an agreement to acquire substantially all of the assets of Edison Mission Energy, or EME.  EME, through its subsidiaries and affiliates, owns, operates, and leases a portfolio of 8,000 MW consisting of wind energy facilities and coal- and gas-fired generating facilities. On December 17, 2012, EME and certain of its direct and indirect subsidiaries filed voluntary petitions for relief under chapter 11 of title 11 of the United States Code, or the Bankruptcy Code.  EME was deconsolidated from its parent company, Edison International, for financial statement purposes but not for tax purposes on December 17, 2012.  On May 2, 2013, certain other subsidiaries of EME filed voluntary petitions for relief under the Bankruptcy Code.
	The Company expects to pay an aggregate purchase price of $2.6 billion (subject to adjustment), which will consist of 12,671,977 shares of NRG common stock (valued at $350 million based upon the volume-weighted average trading price over the 20 trading days prior to October 18, 2013) with the balance to be paid in cash. The Company expects to fund the net cash portion of the purchase price using a combination of cash on hand, including acquired cash on hand of $1.1 billion, and approximately $700 million in newly-issued corporate debt. The Company also expects to assume debt related to acquired project assets of approximately $1.5 billion, which will be non-recourse to NRG.
	In connection with the transaction, NRG has agreed to certain conditions with the parties to the Powerton and Joliet, or POJO, sale-leaseback transaction subject to which an NRG subsidiary will assume the POJO leveraged leases and NRG will guarantee the remaining payments under each lease. In connection with this agreement, NRG has committed to fund up to $350 million in capital expenditures for plant modifications at Powerton and Joliet to install controls to comply with MATS.
	The acquisition is subject to customary conditions, including approval of the U.S. Bankruptcy Court for the Northern District of Illinois and required regulatory approvals, and is expected to close by the end of the first quarter of 2014.  Under certain circumstances, including if EME enters into an alternative transaction, NRG will receive a cash fee of $65 million plus expense reimbursement.  There are no assurances that the conditions to the acquisition of EME will be satisfied, that EME will not enter into an alternative transaction, or that the acquisition of EME will be consummated on the terms agreed to, if at all.
	Energy Systems — On December 31, 2013, NRG Energy Center Omaha Holdings, LLC, an indirect wholly owned subsidiary of NRG Yield LLC, acquired 100% of Energy Systems Company, or Energy Systems, for approximately $120 million. The acquisition was financed from cash on hand. Energy Systems is an operator of steam and chilled thermal facilities that provides heating and cooling services to nonresidential customers in Omaha, Nebraska. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to property, plant and equipment of $60 million, customer relationships of $59 million, and working capital of $1 million. The initial accounting for the business combination is not complete because the evaluations necessary to assess the fair values of certain net assets acquired and the amount of goodwill to be recognized are still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.
	The provisional fair values of the intangible assets at the acquisition date were 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. Significant inputs were as follows:
	•Customer relationships - The customer relationships were valued using a variation of the income approach. Under this approach, the present value of the expected future cash flows resulting from existing customer relationships, considering attrition and charges for contributory assets (such as working capital, fixed assets, and workforce) utilized in the business were estimated and then discounted back at an integrated utility peer group's weighted average cost of capital adjusted to be consistent with the risk inherent in the cash flows. The customer relationships are amortized to depreciation and amortization expense, on a straight-line basis, over 33 years.
	Significant considerations in determining fair value measurements as defined in ASC 820 of the assets acquired and liabilities assumed are as follows:
	•Property, plant & equipment - The fair value of property, plant and equipment acquired were valued utilizing the cost approach. Under this approach, the fair value approximates the current cost of replacing an asset with another of equivalent economic utility adjusted for functional obsolescence and physical depreciation.
	Gregory — On August 7, 2013, NRG Texas Gregory, LLC, a wholly owned subsidiary of NRG, acquired Gregory Power Partners, L.P. for approximately $245 million in cash, net of $32 million cash acquired. Gregory is a cogeneration plant located in Corpus Christi, Texas, which has generation capacity of 388 MW and steam capacity of 160 MWt. The Gregory cogeneration plant provides steam, processed water and a small percentage of its electrical generation to the Corpus Christi Sherwin Alumina plant. The majority of the plant's generation is available for sale in the ERCOT market. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was provisionally allocated to property, plant, and equipment of $248 million, current assets of $13 million, and other liabilities of $16 million. The initial accounting for the business combination is not complete because the evaluations necessary to assess the fair value of certain net assets acquired are still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.
	Significant considerations in determining fair value measurements as defined in ASC 820 of the assets acquired and liabilities assumed are as follows:
	•Property, plant & equipment - The fair value of property, plant and equipment acquired were valued utilizing the cost approach. Under this approach, the fair value approximates the current cost of replacing an asset with another of equivalent economic utility adjusted for functional obsolescence and physical depreciation.
	2012 Acquisitions
	GenOn Energy, Inc. — On December 14, 2012, NRG acquired GenOn Energy, Inc., or GenOn.  GenOn, a generator of wholesale electricity, has baseload, intermediate and peaking power generation facilities using coal, natural gas and oil, totaling approximately 21,440 MW.  The Company issued, as consideration for the acquisition, 0.1216 shares of NRG common stock for each outstanding share of GenOn, including restricted stock units outstanding, on the acquisition date, except for fractional shares which were paid in cash.  The Company issued approximately 93.9 million shares of NRG common stock, or 29% of total common shares outstanding following the closing of the transaction. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The accounting for the GenOn acquisition was completed on December 13, 2013 at which point the fair values became final. The provisional amounts were subject to revision until the evaluations were completed to the extent that additional information was obtained about the facts and circumstances that existed as of the acquisition date. Any changes made to the fair value assessments affected the gain on bargain purchase.
	The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of the acquisition date as well as adjustments made through December 13, 2013 to the amounts initially recorded in 2012 due to the ongoing evaluation of initial estimates. The measurement period adjustments were recorded as an adjustment to the gain on bargain purchase and did not have a significant impact on the Company's consolidated cash flows or financial position in any period. The purchase price of $2.2 billion was allocated as follows:
	(In millions)	Amounts Recognized		Measurement Period Adjustments			Amounts Recognized
		as of Acquisition Date					as of Acquisition Date
		(as previously reported)					(as adjusted)
	Assets
	Cash	$	983	$	—		$	983
	Current and non-current assets	1,385		28			1,413
	Property, plant and equipment	3,936		(115		)	3,821
	Derivative assets	1,157		—			1,157
	Deferred income taxes	2,265		(58		)	2,207
	Total assets acquired	$	9,726	$	(145	)	$	9,581
	Liabilities
	Current and non-current liabilities	$	1,312	$	54		$	1,366
	Out-of-market contracts and leases	1,064		62			1,126
	Derivative liabilities	399		—			399
	Long-term debt and capital leases	4,203		3			4,206
	Total liabilities assumed	6,978		119			7,097
	Net assets acquired	2,748		(264		)	2,484
	Consideration paid	2,188					2,188
	Gain on bargain purchase	$	560	$	(264	)	$	296
	The measurement period adjustments for property, plant and equipment and out-of market liabilities primarily reflect revisions of various estimates based on additional information available. In addition, measurement period adjustments were recorded for additional environmental reserves resulting from further review and revisions to various estimates. The difference between the historical tax basis of the assets and liabilities over the net amount assigned to the assets and liabilities in acquisition accounting was recorded as a net deferred tax asset. In addition, the deferred tax assets associated with net operating losses and other deferred tax benefits were adjusted to reflect the amount expected to be realized in the post-acquisition period.
	2012 Dispositions
	Agua Caliente — On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of the Agua Caliente project, to MidAmerican Energy Holdings Company, or MidAmerican. A majority of the $122 million of cash consideration received at closing represented 49% of construction costs funded by NRG's equity contributions. The excess of the consideration over the carrying value of the divested interest was recorded to additional paid-in capital. MidAmerican will fund its proportionate share of future equity contributions and other credit support for the project. NRG continues to hold a majority interest in and consolidate the project.
	Saale Energie GmbH — On July 17, 2012, the Company completed the sale of its 100% interest in Saale Energie GmbH, or SEG, which holds a 41.9% interest in Kraftwerke Schkopau GbR and a 44.4% interest in Kraftwerke Schkopau Betriebsgesllschaft mbH, collectively, Schkopau. Schkopau holds a fixed 400 MW participation in the 900 MW Schkopau Power Station located in Germany. In connection with the sale of Schkopau, NRG entered into a foreign currency swap contract to hedge the impact of exchange rate fluctuations on the sale proceeds of €141 million. The Company received cash consideration, net of selling expenses, of $174 million, which included $4 million related to the settlement of the swap contract that was recorded as a gain within Other income, net in the quarter ended September 30, 2012. The cash consideration approximated the book value of the net assets, including cash of $38 million, on the date of the sale.
	2011 Acquisitions
	Energy Plus — On September 30, 2011, NRG acquired Energy Plus for $194 million in cash, net of $5 million cash acquired, funded from cash on hand. Energy Plus is a retail electricity provider with 188,000 customers as of December 31, 2011, concentrated in the Northeast markets, and a unique sales channel involving exclusive loyalty and affinity program partnerships. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to customer relationships of $63 million, marketing partnerships of $88 million, trade names of $10 million and goodwill of $29 million. The factors that resulted in goodwill arising from the acquisition include the revenues associated with expanding the Energy Plus retail business and its unique sales channel in new regions, expanding its loyalty and affinity program partnerships and the synergies associated with combining the business with NRG's generation assets. The accounting for the Energy Plus acquisition was completed as of March 31, 2012, at which point the provisional fair values became final with no material changes.
	Solar Acquisitions — During the year ended December 31, 2011, NRG acquired stakes in three Utility Scale Solar facilities for approximately $165 million in cash consideration, as part of the Company's initiative to capture opportunities for future growth in renewables. Subsequent to the acquisition dates in 2011, NRG made capital contributions into these projects of $868 million. In addition, NRG has a commitment to contribute additional amounts into the projects, comprised of $66 million in letters of credit as of December 31, 2013. The Company may increase its letters of credit to replace the restricted cash at its discretion. NRG's minority partners had contributed approximately $413 million of equity subsequent to the acquisition through December 31, 2013 and had additional equity commitments of $64 million as of December 31, 2013. These acquisitions were recorded as business combinations under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date.
	The acquisitions of these three solar facilities are further described below:
	California Valley Solar Ranch — On September 30, 2011, NRG Solar LLC, a wholly-owned subsidiary of NRG, acquired 100% of the 250 MW California Valley Solar Ranch project, or CVSR, in eastern San Luis Obispo County, California. During the second quarter of 2012, the Company met the conditions necessary to permit loan disbursements under the CVSR Financing Agreement, as discussed in Note 12, Debt and Capital Leases. Operations commenced on the first 22 MW phase in September 2012 and 105 MWs for Phases 2 and 4 in December 2012. For the completion of the final phase, 21 MWs commenced operation in the third quarter of 2013 and 102 MWs commenced operation in October 2013. Power generated from CVSR is sold to PG&E under a 25 year PPA.
	Agua Caliente — On August 5, 2011, NRG, through its wholly-owned subsidiary, NRG Solar PV LLC, acquired 100% of the 290 MW Agua Caliente solar project in Yuma, AZ. On January 18, 2012, the Company completed the sale of a 49% interest to MidAmerican Energy Holdings Company as discussed above. Power generated from Agua Caliente is sold to PG&E under a 25 year PPA. Full commercial operations of the entire 290 MW project was achieved as of September 30, 2013.
	Ivanpah — On April 5, 2011, NRG acquired a 50.1% stake in the 378 MW Ivanpah Solar Electric Generation System, or Ivanpah, from BrightSource Energy, Inc., or BSE. BSE maintained a 21.8% interest in Ivanpah and the remaining 28.1% was acquired by a wholly-owned subsidiary of Google. Ivanpah is composed of three separate facilities - Ivanpah 1 (126 MW), Ivanpah 2 (133 MW), and Ivanpah 3 (133 MW). Ivanpah achieved operations as of December 31, 2013. Power generated from Ivanpah is sold to Southern California Edison and Pacific Gas and Electric, under multiple 20 to 25 year PPAs.
	The purchase price for these acquisitions, considered business combinations, was primarily allocated to $767 million of property, plant and equipment, $489 million of accrued expenses, $60 million of other assets, including restricted cash, and $19 million of other liabilities. The accounting for these acquisitions was completed as of March 31, 2012, at which point the provisional fair values became final with no material changes.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments (Notes)	12 Months Ended
	Dec. 31, 2013
Fair Value of Financial Instruments Disclosure [Abstract]	'
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments
	For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
	The estimated carrying values and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:
		As of December 31,
		2013				2012
		Carrying Amount		Fair Value		Carrying Amount			Fair Value
		(In millions)
	Assets
	Notes receivable (a)	$	99	$	99	$	88		$	88
	Liabilities
	Long-term debt, including current portion	16,804		17,222		15,866			16,492
	(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.
	The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non publicly-traded long-term debt, and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy.
	Fair Value Accounting under ASC 820
	ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
	•	Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.
	•	Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forward contracts.
	•	Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.
	In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
	Recurring Fair Value Measurements
	Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.
	The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
		As of December 31, 2013
		Fair Value
		Level 1		Level 2		Level 3			Total
		(In millions)
	Investment in available-for-sale securities (classified within other non-current assets):
	Debt securities	$	—	$	—	$	16		$	16
	Available-for-sale securities	2		—		—			2
	Other (a)	37		—		10			47
	Nuclear trust fund investments:
	Cash and cash equivalents	26		—		—			26
	U.S. government and federal agency obligations	40		5		—			45
	Federal agency mortgage-backed securities	—		62		—			62
	Commercial mortgage-backed securities	—		14		—			14
	Corporate debt securities	—		70		—			70
	Equity securities	276		—		56			332
	Foreign government fixed income securities	—		2		—			2
	Other trust fund investments:
	U.S. government and federal agency obligations	1		—		—			1
	Derivative assets:
	Commodity contracts	346		1,126		147			1,619
	Interest rate contracts	—		20		—			20
	Total assets	$	728	$	1,299	$	229		$	2,256
	Derivative liabilities:
	Commodity contracts	$	216	$	831	$	134		$	1,181
	Interest rate contracts	—		69		—			69
	Total liabilities	$	216	$	900	$	134		$	1,250
	(a)	Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for some key and highly compensated employees and a total return swap that does not meet the definition of a derivative.
		As of December 31, 2012
		Fair Value
		Level 1		Level 2		Level 3			Total
		(In millions)
	Investment in available-for-sale securities (classified within other non-current assets):
	Debt securities	$	—	$	—	$	12		$	12
	Other (a)	22		—		—			22
	Nuclear trust fund investments:
	Cash and cash equivalents	10		—		—			10
	U.S. government and federal agency obligations	33		—		—			33
	Federal agency mortgage-backed securities	—		59		—			59
	Commercial mortgage-backed securities	—		9		—			9
	Corporate debt securities	—		80		—			80
	Equity securities	233		—		47			280
Foreign government fixed income securities	—		2		—			2
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—			1
Derivative assets:
Commodity contracts	1,457		1,711		135			3,303
Interest rate contracts	—		3		—			3
Total assets	$	1,756	$	1,864	$	194		$	3,814
Derivative liabilities:
Commodity contracts	$	1,144	$	1,047	$	147		$	2,338
Interest rate contracts	—		143		—			143
Total liabilities	$	1,144	$	1,190	$	147		$	2,481
(a)	Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for some key and highly compensated employees.
There have been no transfers during the year ended December 31, 2013, between Levels 1 and 2. The following tables reconcile, for the years ended December 31, 2013, and 2012, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:
	For the Year Ended December 31, 2013
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt		Other		Trust Fund			Derivatives (a)			Total
	Securities				Investments
	(In millions)
Beginning balance as of January 1, 2013	$	12	$	—	$	47		$	(12	)	$	47
Total gains and losses (realized/unrealized):
Included in OCI	4		—		—			—			4
Included in earnings	—		—		—			(12		)	(12		)
Included in nuclear decommissioning obligations	—		—		10			—			10
Purchases	—		10		2			4			16
Sales	—		—		(3		)	—			(3		)
Transfers into Level 3 (b)	—		—		—			6			6
Transfers out of Level 3 (b)	—		—		—			27			27
Ending balance as of December 31, 2013	$	16	$	10	$	56		$	13		$	95
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2013	$	—	$	—	$	—		$	1		$	1
(a)	Consists of derivatives assets and liabilities, net.
(b)	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
	For the Year Ended December 31, 2012
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt		Trust Fund		Derivatives (a)			Total
	Securities		Investments
	(In millions)
Beginning balance as of January 1, 2012	$	7	$	42	$	8		$	57
Total gains and losses (realized/unrealized):
Included in OCI	5		—		—			5
Included in earnings	—		—		(13		)	(13		)
Included in nuclear decommissioning obligations	—		5		—			5
Purchases	—		—		8			8
Contracts acquired in GenOn acquisition	—		—		18			18
Transfers into Level 3 (b)	—		—		(33		)	(33		)
Transfer out of Level 3 (b)	—		—		—			—
Ending balance as of December 31, 2012	$	12	$	47	$	(12	)	$	47
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2012	$	—	$	—	$	(3	)	$	(3	)
(a)	Consists of derivatives assets and liabilities, net.
(b)	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations.
Non-derivative fair value measurements
NRG's investments in debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued based on third-party market value assessments.
The trust fund investments are held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, U.S. government and federal agency obligations are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of corporate debt securities are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Certain equity securities, classified as commingled funds, are analogous to mutual funds, are maintained by investment companies, and hold certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities classified as commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See also Note 6, Nuclear Decommissioning Trust Fund.
Derivative fair value measurements
A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 9% of derivative assets and 11% of derivative liabilities. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2013, the credit reserve resulted in a $1 million decrease in fair value which is reflected as a $1 million loss in operating revenue and cost of operations.
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2013, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
Under the guidance of ASC 815, entities may choose to offset cash collateral paid or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2013, the Company recorded $276 million of cash collateral paid and $63 million of cash collateral received on its balance sheet.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, the following item is a discussion of the concentration of credit risk for the Company's financial instruments. 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, 2013, counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $813 million and NRG held collateral (cash and letters of credit) against those positions of $5 million, resulting in a net exposure of $808 million. Approximately 87% of the Company's exposure before collateral is expected to roll off by the end of 2015. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. 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. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.
Category	Net Exposure (a)
	(% of Total)
Financial institutions	52	%
Utilities, energy merchants, marketers and other	29
Coal and emissions	1
ISOs	18
Total	100	%
Category	Net Exposure (a)
	(% of Total)
Investment grade	94	%
Non-Rated	6
Total	100	%
(a)	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.
NRG has counterparty credit risk exposure to certain counterparties, each of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $349 million. 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 agreements, 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 values 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, 2013, aggregate credit risk exposure managed by NRG to these counterparties was approximately $2.3 billion, including $797 million related to assets of NRG Yield, Inc., for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations, which NRG is unable to predict. In the case of the coal supply agreement, NRG holds a lien against the underlying asset which significantly reduces the risk of loss.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Company's 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 may result from both nonpayment of customer accounts receivable and the loss of 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, 2013, the Company's retail customer credit exposure to C&I customers was diversified across many customers and various industries, as well as government entities.
NRG is also exposed to retail customer credit risk relating to its Mass customers, which may result in a write-off of bad debt. The Company's bad debt expense was $67 million and $45 million for the years ending December 31, 2013 and 2012, respectively. 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.

Accounting_for_Derivative_Inst

Accounting for Derivative Instruments and Hedging Activities (Notes)	12 Months Ended
	Dec. 31, 2013
Accounting for Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Accounting for Derivative Instruments and Hedging Activities	'
	Accounting for Derivative Instruments and Hedging Activities
	ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. NRG may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the effective portion of the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
	For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings.
	For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG's energy related commodity contracts, interest rate swaps, and foreign exchange contracts.
	As the Company engages principally in the trading and marketing of its generation assets and Retail Business, some of NRG's commercial activities qualify for hedge accounting. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company's baseload plants. For this reason, many trades in support of NRG's baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG's peaking unit's asset optimization will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the retail supply and fuels supply contracts are recorded under mark-to-market accounting. All of NRG's hedging and trading activities are subject to limits within the Company's Risk Management Policy.
	Energy-Related Commodities
	To manage the commodity price risk associated with the Company's competitive supply activities and the price risk associated with wholesale power sales from the Company's electric generation facilities and retail power sales from the Retail Business, NRG enters into a variety of derivative and non-derivative hedging instruments, utilizing the following:
	•	Forward contracts, which commit NRG to purchase or sell energy commodities or purchase fuels in the future.
	•	Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.
	•	Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity.
	•	Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity.
	•	Extendable swaps, which include a combination of swaps and options executed simultaneously for different periods. This combination of instruments allows NRG to sell out-year volatility through call options in exchange for natural gas swaps with fixed prices in excess of the market price for natural gas at that time. The above-market swap combined with its later-year call option are priced in aggregate at market at the trade's inception.
	•	Weather and hurricane derivative products used to mitigate a portion of Reliant Energy's lost revenue due to weather.
	The objectives for entering into derivative contracts designated as hedges include:
	•	Fixing the price for a portion of anticipated future electricity sales that provides an acceptable return on the Company's electric generation operations.
	•	Fixing the price of a portion of anticipated fuel purchases for the operation of NRG's power plants.
	•	Fixing the price of a portion of anticipated power purchases for the Company's retail sales.
	NRG's trading and hedging activities are subject to limits within 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.
	As of December 31, 2013, NRG's derivative assets and liabilities consisted primarily of the following:
	•	Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG's generation assets' forecasted output or NRG's retail load obligations through 2019.
	•	Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2017.
	•	Cash flow hedge energy-related derivative financial instruments extending through December 2015.
	Also, as of December 31, 2013, NRG had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows:
	•	Load-following forward electric sale contracts extending through 2026;
	•	Power Tolling contracts through 2038;
	•	Coal purchase contract through 2020;
	•	Power transmission contracts through 2015;
	•	Natural gas transportation contracts and storage agreements through 2028; and
	•	Coal transportation contracts through 2020.
	Interest Rate Swaps
	NRG is exposed to changes in interest rates through the Company's issuance of variable and fixed rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of December 31, 2013, NRG had interest rate derivative instruments on non-recourse debt extending through 2030, the majority of which are designated as cash flow hedges.
	Volumetric Underlying Derivative Transactions
	The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2013 and 2012. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.
			Total Volume
	Commodity	Units	December 31, 2013				December 31, 2012
			(In millions)
	Emissions	Short Ton	—				(1		)
	Coal	Short Ton	51				37
	Natural Gas	MMBtu	(166		)		(413		)
	Oil	Barrel	1				1
	Power	MWh	(27		)		(14		)
	Interest	Dollars	$	1,444			$	2,612
	The decrease in the natural gas position was the result of additional purchases entered into during the year to hedge our retail portfolio as well as the settlement of positions during the period. These amounts were slightly offset by natural gas sales entered into during the year to hedge our conventional power generation. The decrease in the interest rate position was primarily the result of the settlement of interest rate swaps.
	Fair Value of Derivative Instruments
	The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:
		Fair Value
		Derivative Assets								Derivative Liabilities
	(In millions)	December 31, 2013				December 31, 2012				December 31, 2013			December 31, 2012
	Derivatives Designated as Cash Flow or Fair Value Hedges:
	Interest rate contracts current	$	—			$	—			$	35		$	29
	Interest rate contracts long-term	14				3				29			96
	Commodity contracts current	—				—				1			3
	Commodity contracts long-term	—				—				1			1
	Total Derivatives Designated as Cash Flow or Fair Value Hedges	14				3				66			129
	Derivatives Not Designated as Cash Flow or Fair Value Hedges:
	Interest rate contracts current	—				—				4			7
	Interest rate contracts long-term	6				—				1			11
	Commodity contracts current	1,328				2,644				1,015			1,942
	Commodity contracts long-term	291				659				164			392
	Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	1,625				3,303				1,184			2,352
	Total Derivatives	$	1,639			$	3,306			$	1,250		$	2,481
	The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting derivatives by counterparty master agreement level and collateral received or paid:
		Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets/Liabilities				Derivative Instruments				Cash Collateral (Held)/Posted			Net Amount
As of December 31, 2013	(in millions)
Commodity contracts:
Derivative assets	$	1,619			$	(1,032	)		$	(62	)	$	525
Derivative liabilities	(1,181		)		1,032				18			(131		)
Total commodity contracts	438				—				(44		)	394
Interest rate contracts:
Derivative assets	20				(12		)		—			8
Derivative liabilities	(69		)		12				—			(57		)
Total interest rate contracts	(49		)		—				—			(49		)
Total derivative instruments	$	389			$	—			$	(44	)	$	345
	Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets/Liabilities				Derivative Instruments				Cash Collateral (Held)/Posted			Net Amount
As of December 31, 2012	(in millions)
Commodity contracts:
Derivative assets	$	3,303			$	(2,024	)		$	(374	)	$	905
Derivative liabilities	(2,338		)		2,024				28			(286		)
Total commodity contracts	965				—				(346		)	619
Interest rate contracts:
Derivative assets	3				—				—			3
Derivative liabilities	(143		)		—				—			(143		)
Total interest rate contracts	(140		)		—				—			(140		)
Total derivative instruments	$	825			$	—			$	(346	)	$	479
Accumulated Other Comprehensive Income
The following tables summarize the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
	Year Ended December 31, 2013
	Energy				Interest				Total
	Commodities				Rate
	(In millions)
Accumulated OCI balance at December 31, 2012	$	41			$	(72	)		$	(31	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(51		)		20				(31		)
Mark-to-market of cash flow hedge accounting contracts	9				30				39
Accumulated OCI balance at December 31, 2013, net of $14 tax	(1		)		(22		)		(23		)
Losses expected to be realized from OCI during the next 12 months, net of $8 tax	$	(1	)		$	(14	)		$	(15	)
There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2013.
	Year Ended December 31, 2012
	Energy				Interest				Total
	Commodities				Rate
	(In millions)
Accumulated OCI balance at December 31, 2011	$	188			$	(56	)		$	132
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(144		)		23				(121		)
Mark-to-market of cash flow hedge accounting contracts	(3		)		(39		)		(42		)
Accumulated OCI balance at December 31, 2012, net of $7 tax	$	41			$	(72	)		$	(31	)
Losses recognized in income from the ineffective portion of cash flow hedges	$	(51	)		$	—			$	(51	)
	Year Ended December 31, 2011
	Energy				Interest				Total
	Commodities				Rate Contracts
	(In millions)
Accumulated OCI balance at December 31, 2010	$	488			$	(47	)		$	441
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(374		)		12				(362		)
Mark-to-market of cash flow hedge accounting contracts	74				(21		)		53
Accumulated OCI balance at December 31, 2011, net of $87 tax	$	188			$	(56	)		$	132
Gains recognized in income from the ineffective portion of cash flow hedges	$	28			$	3			$	31
Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts.
Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of April 30, 2012, the Company's regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar year 2012. As a result, the Company de-designated its 2012 ERCOT cash flow hedges as of April 30, 2012, and prospectively marked these derivatives to market through the income statement.
Impact of Derivative Instruments on the Statement of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period earnings.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges, and trading activity on NRG's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.
	Year Ended December 31,
	2013				2012				2011
	(In millions)
Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(105	)		$	(247	)		$	54
Reversal of (gain)/loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions	(357		)		20				107
Net unrealized gains/(losses) on open positions related to economic hedges	177				10				(33		)
(Losses)/gains on ineffectiveness associated with open positions treated as cash flow hedges	—				(51		)		28
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(285		)		(268		)		156
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(50		)		(60		)		21
Net unrealized gains on open positions related to trading activity	7				46				42
Total unrealized mark-to-market (losses)/gains for trading activity	(43		)		(14		)		63
Total unrealized (losses)/gains	$	(328	)		$	(282	)		$	219
	Year Ended December 31,
	2013				2012				2011
	(In millions)
Unrealized (losses)/gains included in operating revenues	$	(621	)		$	(464	)		$	388
Unrealized gains/(losses) included in cost of operations	293				182				(169		)
Total impact to statement of operations — energy commodities	$	(328	)		$	(282	)		$	219
Total impact to statement of operations — interest rate contracts	$	15			$	(8	)		$	2
The reversal of gain or loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions were valued based upon the forward prices on the acquisition dates. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in revenue or cost of operations during the same period.
For the year ended December 31, 2013, the $177 million gain from economic hedge positions was primarily the result of an increase in value of forward sales of natural gas and electricity due to a decrease in forward power and gas prices and an increase in value of forward purchases of coal due to an increase in forward coal prices.
As of June 30, 2013, NRG had interest rate swaps designated as cash flow hedges on the CVSR solar project. The notional amount on the swaps exceeded the actual debt draws on the project. As such, NRG discontinued cash flow hedge accounting for these contracts and $5 million of loss previously deferred in OCI was recognized in earnings for the year ended December 31, 2013.
For the year ended December 31, 2012, the $10 million gain from economic hedge positions was the result of an increase in value of forward sales of natural gas and electricity due to a decrease in forward power and gas prices offset by a decrease in value of forward purchases of coal due to a decrease in forward coal prices.
As of June 30, 2012 NRG had interest rate swaps designated as cash flow hedges on the Alpine solar project. The notional amount of the swaps exceeded the actual debt draws on the project. As such, NRG discontinued cash flow hedge accounting for these contracts and $4 million of loss previously deferred in OCI was recognized in earnings for the year ended December 31, 2012.
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 net liability positions as of December 31, 2013, was $85 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2013, was $15 million. The Company is also a party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, of approximately $34 million as of December 31, 2013.
See Note 4, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.

Nuclear_Decommissioning_Trust_

Nuclear Decommissioning Trust Fund (Notes)	12 Months Ended
	Dec. 31, 2013
Nuclear Decommissioning Trust Fund Disclosure [Abstract]	'
Nuclear Decommissioning Trust Fund	'
	Nuclear Decommissioning Trust Fund
	NRG's nuclear decommissioning trust fund assets, which are for the decommissioning of STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rates charged to rate payers all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities.
	NRG accounts for the nuclear decommissioning trust fund in accordance with ASC 980, Regulated Operations, or ASC 980 because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.
	The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
		As of December 31, 2013										As of December 31, 2012
	(In millions, except otherwise noted)	Fair			Unrealized			Unrealized			Weighted-	Fair		Unrealized		Weighted-
		Value			Gains			Losses			average	Value		Gains (a)		average
											maturities					maturities
											(in years)					(in years)
	Cash and cash equivalents	$	26		$	—		$	—		—	$	10	$	—	—
	U.S. government and federal agency obligations	45			1			1			9	33		2		10
	Federal agency mortgage-backed securities	62			1			1			24	59		2		23
	Commercial mortgage-backed securities	14			—			—			29	9		—		30
	Corporate debt securities	70			1			1			9	80		4		11
	Equity securities	332			204			—			—	280		143		—
	Foreign government fixed income securities	2			—			—			9	2		—		6
	Total	$	551		$	207		$	3			$	473	$	151
	(a) There are no unrealized losses as of December 31, 2012.
	The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.
		Year Ended December 31,
		2013			2012			2011
		(In millions)
	Realized gains	$	25		$	12		$	4
	Realized losses	(8		)	(7		)	(3		)
	Proceeds from sale of securities	488			399			385

Inventory_Notes

Inventory (Notes)	12 Months Ended
	Dec. 31, 2013
Inventory Disclosure [Abstract]	'
Inventory	'
	Inventory
	Inventory consisted of:
		As of December 31,
		2013		2012
		(In millions)
	Fuel oil	$	259	$	181
	Coal/Lignite	290		405
	Natural gas	15		12
	Spare parts	316		301
	Other	18		4
	Total Inventory	$	898	$	903

Notes_Receivable_Notes

Notes Receivable (Notes)	12 Months Ended
	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]	'
Capital Leases and Notes Receivable	'
	Notes Receivable
	Notes receivable primarily consisted of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. NRG's notes receivable and capital leases were as follows:
		As of December 31,
		2013		2012
		(In millions)
	Notes receivable — non-affiliates (a)	$	97	$	82
	Notes receivable — affiliate
	Avenal Solar Holdings LLC, indefinite maturity date, 4.5% (b)	2		6
	Total notes receivable	99		88
	Less current maturities(c)	26		9
	Total notes receivable — noncurrent	$	73	$	79
	(a)	Primarily relates to Agua Caliente, Alpine, Borrego, El Segundo Energy Center and CVSR's agreements with their respective transmission owners to provide financing for required network upgrades. The notes will be repaid within a five year period following the date each facility reaches commercial operations.
	(b)	NRG entered into a long-term $35 million note receivable facility with Avenal Solar Holdings LLC, to fund project liquidity needs in 2011.
	(c)	The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

Property_Plant_and_Equipment_N

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment	'
	Property, Plant and Equipment
	NRG's major classes of property, plant, and equipment were as follows:
		As of December 31,						Depreciable
		2013			2012			Lives
		(In millions)
	Facilities and equipment	$	22,087		$	19,571		1-40 Years
	Land and improvements	801			793
	Nuclear fuel	463			414			5 Years
	Office furnishings and equipment	298			355			2-10 Years
	Construction in progress	2,775			4,428
	Total property, plant, and equipment	26,424			25,561
	Accumulated depreciation	(6,573		)	(5,408		)
	Net property, plant, and equipment	$	19,851		$	20,153

Asset_Impairments_Notes

Asset Impairments (Notes)	12 Months Ended
	Dec. 31, 2013
Asset Impairment Charges [Abstract]	'
Asset Impairments	'
	Asset Impairments
	2013 Impairment Losses
	Indian River - Annually during the fourth quarter, the Company revises its views of power and fuel prices including the Company's fundamental view for long term prices in connection with the preparation of its annual budget. Changes to the Company’s views of long term power and fuel prices impacted the Company’s projections of profitability, 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. The Company's revised views of projected profitability for Indian River resulted in a significant adverse change in the extent to which the assets are expected to be used. As a result, the Company considered this to be an indicator of impairment and performed an impairment test for these assets under ASC 360, Property, Plant and Equipment. The carrying amount of the assets was lower than the future net cash flows expected to be generated by the asset, considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. As a result, the assets are considered to be impaired, and the Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets. The fair value of the assets was determined by factoring in the probability weighting of different courses of action available to the Company and included both an income approach and a market approach. The Company recorded an impairment loss related to Indian River in the fourth quarter of 2013 of $459 million.
	Gladstone - During the fourth quarter of 2013, the Company reviewed its 37.5% interest in Gladstone for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements, due to future market expectations as well as discussions with the managing joint venture participants regarding the plant's expected life. In determining fair value, the Company utilized an income approach and considered project specific assumptions for future project operating revenues and costs and expected plant operations. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other than temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and fair value of the investment and recorded an impairment loss in the fourth quarter of 2013 of $92 million.
	2011 Impairment Losses
	Emissions Allowances - Under CSAPR, use of discounted Acid Rain SO2 and CAIR NOx allowances would have been discontinued and replaced with completely distinct allowance programs. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. During the year ended December 31, 2011, the Company recorded an impairment charge of $160 million on the Company's Acid Rain Program SO2 emission allowances in order to comply with the Acid Rain Program as discussed in Note 24, Environmental Matters.
	Nuclear Innovation North America, LLC (NINA) - NINA is majority-owned subsidiary of NRG established to develop, finance and invest in new advanced design nuclear projects in select markets across North America, including the planned South Texas Project Units 3 and 4 Project, or STP 3 & 4. On March 11, 2011, Japan was hit by a devastating earthquake and tsunami which, in turn, triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station. The nuclear incident in Japan introduced multiple and substantial uncertainties around new nuclear development in the United States and the availability of debt and equity financing to NINA. Consequently, NINA announced, on March 21, 2011, that it was reducing the scope of development at the STP 3 & 4 expansion and suspended indefinitely all detailed engineering work and other pre-construction activities. As a result, NRG announced that, while it will cooperate with and support its current partners and any prospective future partners in attempting to develop STP 3 & 4 successfully, it was withdrawing from further financial participation in NINA's development of STP 3 & 4.
	Due to the events described above, NRG evaluated its investment in NINA for impairment. As part of this process, NRG evaluated the contractual rights and economic interests held by the various stakeholders in NINA, and concluded that while it continues to hold majority legal ownership, NRG ceased to have a controlling financial interest in NINA at the end of the first quarter of 2011. Consequently, NRG deconsolidated NINA as of March 31, 2011, in accordance with ASC 810. Furthermore, NRG concluded it was remote that NRG would recover any portion of the carrying amount of its equity investment in NINA and, consequently, recorded impairment charges related to the full amount of its investment, as well as additional contributions made to support the reduced scope of work. The impairment charges totaled $495 million for the year ended December 31, 2011. In 2012, NRG recorded an additional impairment charge related to additional contributions made of $2 million.

Goodwill_and_Other_Intangibles

Goodwill and Other Intangibles (Notes)	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Goodwill and Other Intangibles	'
	Goodwill and Other Intangibles
	Goodwill — NRG's goodwill balance was $2.0 billion as of December 31, 2013 and 2012. The Company recorded approximately $1.7 billion of goodwill in connection with the acquisition of Texas Genco in 2006. The Company recorded $144 million of goodwill in connection with the 2010 acquisition of Green Mountain Energy, and $29 million in connection with the 2011 acquisition of Energy Plus. In 2013 and 2012, the Company recorded additional goodwill for several business acquisitions. The Energy Plus acquisition is discussed further in Note 3, Business Acquisitions and Dispositions. As of December 31, 2013, there was no impairment to goodwill. As of December 31, 2013, 2012, and 2011, NRG had approximately $573 million, $609 million, and $594 million, respectively, of goodwill that is deductible for U.S. income tax purposes in future periods.
	Intangible Assets — The Company's intangible assets as of December 31, 2013, primarily reflect intangible assets established with the acquisitions of various companies in 2013, 2012, 2011, 2010, 2009, and 2006, and are comprised of the following:
	•	Emission Allowances — These intangibles primarily consist of SO2 and NOx emission allowances established with the 2012 GenOn acquisition and 2006 Texas Genco acquisition and also include RGGI emission credits which NRG began purchasing in 2009. These emission allowances are held-for-use and are amortized to cost of operations, with NOx allowances amortized on a straight-line basis and SO2 allowances and RGGI credits amortized based on units of production. During the year ended December 31, 2011, the Company recorded an impairment charge of $160 million on the Company's Acid Rain Program SO2 emission allowances in order to comply with the Acid Rain Program as discussed in Note 24, Environmental Matters.
	•	Development rights — Arising primarily from the acquisition of solar businesses in 2010 and 2011, these intangibles are amortizable to depreciation and amortization expense on a straight-line basis over the estimated life of the related project portfolio.
	•	Energy supply contracts — Established with the acquisitions of Reliant Energy and Green Mountain Energy, these represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers. The contracts are amortized to cost of operations based on the expected delivery under the respective contracts.
	•	In-market fuel (gas and nuclear) contracts — These intangibles were established with the Texas Genco acquisition in 2006 and are amortized to cost of operations over expected volumes over the life of each contract.
	•	Customer contracts — Established with the acquisitions of Reliant Energy, Green Mountain Energy, and Northwind Phoenix, these intangibles represent the fair value at the acquisition date of contracts that primarily provide electricity to Reliant Energy's and Green Mountain Energy's C&I customers. These contracts are amortized to revenues based on expected volumes to be delivered for the portfolio.
	•	Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base, primarily for Energy Alternatives, Energy Plus, Reliant Energy, Green Mountain Energy, Energy Systems and Energy Curtailment Specialists. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.
	•	Marketing partnerships — Established with the acquisition of Energy Plus, as further discussed in Note 3, Business Acquisitions and Dispositions, these intangibles represent the fair value at the acquisition date of existing agreements with loyalty and affinity partners. The marketing partnerships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.
	•	Trade names — Established with the Reliant Energy, Green Mountain and Energy Plus acquisitions, these intangibles are amortized to depreciation and amortization expense, on a straight-line basis.
	•	Other — Consists of renewable energy credits, wind intangible assets, costs to extend the operating license for STP Units 1 and 2, the intangible asset related to a purchased ground lease and the value of acquired power purchase agreements.
	The following tables summarize the components of NRG's intangible assets subject to amortization:
								Contracts
	Year Ended December 31, 2013	Emission			Development			Energy			Fuel			Customer			Customer			Marketing Partnerships			Trade			Other			Total
		Allowances			Rights			Supply									Relationships						Names
		(In millions)
	1-Jan-13	$	793		$	24		$	54		$	72		$	859		$	640		$	88		$	318		$	68		$	2,916
	Purchases	76			—			—			—			—			14			—			—			28			118
	Acquisition of businesses	—			—			—			—			—			89			—			—			10			99
	Usage	—			—			—			—			—			—			—			—			(14		)	(14		)
	Other	2			(5		)	—			—			—			—			—			—			1			(2		)
	31-Dec-13	871			19			54			72			859			743			88			318			93			3,117
	Less accumulated amortization	(433		)	—			(36		)	(61		)	(847		)	(487		)	(12		)	(93		)	(8		)	(1,977		)
	Net carrying amount	$	438		$	19		$	18		$	11		$	12		$	256		$	76		$	225		$	85		$	1,140
								Contracts
	Year Ended December 31, 2012	Emission			Development			Energy			Fuel			Customer			Customer			Marketing Partnerships			Trade			Other			Total
		Allowances			Rights			Supply									Relationships						Names
		(In millions)
	1-Jan-12	$	783		$	24		$	54		$	72		$	859		$	634		$	88		$	318		$	39		$	2,871
	Purchases	18			—			—			—			—			—			—			—			18			36
	Acquisition of businesses	53			—			—			—			—			6			—			—			10			69
	Usage	—			—			—			—			—			—			—			—			(13		)	(13		)
	Sales	(4		)	—			—			—			—			—			—			—			—			(4		)
	Write-off of fully amortized balances	(56		)	—			—			—			—			—			—			—			—			(56		)
	Other	(1		)	—			—			—			—			—			—			—			14			13
	31-Dec-12	793			24			54			72			859			640			88			318			68			2,916
	Less accumulated amortization(a)	(329		)	—			(30		)	(59		)	(794		)	(415		)	(4		)	(72		)	(3		)	(1,706		)
	Net carrying amount	$	464		$	24		$	24		$	13		$	65		$	225		$	84		$	246		$	65		$	1,210
	(a) Adjusted for write-off of fully amortized emission allowances of $56 million
	The following table presents NRG's amortization of intangible assets for each of the past three years:
		Years Ended December 31,
	Amortization	2013			2012			2011
		(In millions)
	Emission allowances	$	104		$	50		$	66
	Energy supply contracts	6			5			4
	Fuel contracts	2			2			2
	Customer contracts	53			119			185
	Customer relationships	72			98			109
	Marketing partnerships	8			4			—
	Trade names	29			30			22
	Other	5			2			—
	Total amortization	$	279		$	310		$	388
	The following table presents estimated amortization of NRG's intangible assets for each of the next five years:
								Contracts
	Year Ended December 31,	Emission			Development			Energy			Fuel			Customer			Customer			Marketing Partnerships			Trade			Total
		Allowances			Rights			Supply									Relationships						Names
		(In millions)
	2014	$	77		$	1		$	6		$	2		$	1		$	61		$	15		$	21		$	184
	2015	65			1			6			2			1			45			14			21			155
	2016	64			1			6			2			1			31			9			21			135
	2017	65			1			—			—			1			21			5			21			114
	2018	68			1			—			—			1			10			5			21			106
The following table presents the weighted average remaining amortization period related to NRG's intangible assets purchased in 2013 business acquisitions:
As of December 31, 2013		Customer Relationships
		(In years)
Weighted average remaining amortization period		28
Intangible assets held for sale — From time to time, management may authorize the transfer from the Company's emission bank of emission allowances held-for-use to intangible assets held-for-sale. Emission allowances held-for-sale are included in other non current assets on the Company's consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31, 2013, the value of emission allowances held-for-sale is $24 million and is managed within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.
Out-of-market contracts — Due primarily to business acquisitions, NRG acquired certain out-of-market contracts, which are classified as non-current liabilities on NRG's consolidated balance sheet. These include out-of-market lease contracts of $790 million and out-of-market gas transportation and storage contracts of $327 million acquired in the acquisition of GenOn. These out-of-market contracts are amortized to cost of operations. In addition, the power and customer contracts are amortized to revenues, while the energy supply contracts are amortized to cost of operations.
The following table summarizes the estimated amortization related to NRG's out-of-market contracts:
Year Ended December 31,		Power Contracts			Leases		Gas Transportation			Total
	(In millions)
2014		$	17		39		$	36		$	92
2015		17			39		37			93
2016		18			39		42			99
2017		18			39		37			94
2018		19			39		32			90

Debt_and_Capital_Leases_Notes

Debt and Capital Leases (Notes)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt and Capital Leases	'
	Debt and Capital Leases
	Long-term debt and capital leases consisted of the following:
		As of December 31,
		2013				2012				Interest Rate % (a)
		(In millions except rates)
	NRG Recourse Debt:
	Senior notes, due 2018	$	1,130			$	1,200			7.625
	Senior notes, due 2019	800				800				7.625
	Senior notes, due 2019	602				693				8.5
	Senior notes, due 2020	1,062				1,100				8.25
	Senior notes, due 2021	1,128				1,128				7.875
	Senior notes, due 2023	990				990				6.625
	Term loan facility, due 2018	2,002				1,573				L+3.00/L+2.00
	Indian River Power LLC, tax exempt bonds, due 2040 and 2045	247				247				5.375 - 6.00
	Dunkirk Power LLC, tax exempt bonds, due 2042	59				59				5.875
	Fort Bend County, tax-exempt bonds, due 2038 and 2042	67				28				4.75
	Subtotal NRG Recourse Debt	8,087				7,818
	NRG Non-Recourse Debt:
	GenOn senior notes, due 2014	—				617				7.625
	GenOn senior notes, due 2017	782				800				7.875
	GenOn senior notes, due 2018	780				801				9.5
	GenOn senior notes, due 2020	621				631				9.875
	GenOn Americas Generation senior notes, due 2021	503				509				8.5
	GenOn Americas Generation senior notes, due 2031	435				437				9.125
	NRG Marsh Landing term loan, due 2017 and 2023(b)	473				390				L+2.75 - 3.00
	CVSR - High Plains Ranch II LLC, due 2014 and 2037(b)	1,104				786				0.611 - 3.579
	NRG West Holdings LLC, term loan, due 2023	512				350				L+2.25 - 2.75
	Agua Caliente Solar, LLC, due 2037	878				640				2.395 - 3.633
	Ivanpah Financing, due 2014 and 2038	1,575				1,437				1.116 - 4.256
	South Trent Wind LLC, due 2020	69				72				L+ 2.625
	NRG Peaker Finance Co. LLC, bonds, due 2019	154				173				L+1.07
	NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025(b)	127				137				5.95 - 7.31
	NRG Solar Alpine LLC, due 2014 and 2022(b)	221				2				L+2.25 - 2.50
	NRG Solar Borrego I LLC, due 2024 and 2038(b)	78				—				L+2.50/5.65
	NRG Solar Avra Valley LLC(b)	63				66				L+2.25
	TA - High Desert LLC, due 2014, 2023 and 2033	80				—				L+2.50/5.15
	NRG Solar Kansas South LLC, due 2014 and 2031	58				—				L+2.00 - 2.625
	Other	204				200				various
	Subtotal NRG Non-Recourse Debt	8,717				8,048
	Subtotal Long Term Debt	16,804				15,866
	Capital leases:
	Chalk Point capital lease, due 2015	10				14				8.19
	Other	3				3				various
	Subtotal Capital Leases	13				17
	Subtotal	16,817				15,883
	Less current maturities	1,050				147
	Total long-term debt and capital leases	$	15,767			$	15,736
	(a)	As of December 31, 2013, L+ equals 3 month LIBOR plus x%, with the exception of NRG Solar Alpine LLC cash grant loan and NRG Solar Kansas South LLC and TA - High Desert LLC cash grant bridge loan which are 1 month LIBOR plus x% and NRG Solar Kansas South LLC term loan which is 3 month LIBOR plus x%
	(b)	Debt related to projects in NRG Yield
	Long-term debt includes the following premiums/(discounts):
			As of December 31,
			2013				2012
			(in millions)
	Senior notes, due 2019		$	(5	)		$	(7	)
	Term loan facility, due 2018 (a)		(5		)		(3		)
	NRG Peaker Finance Co. LLC, bonds, due 2019 (b)		(11		)		(15		)
	GenOn senior notes, due 2014 (c)		—				42
	GenOn senior notes, due 2017 (c)		58				75
	GenOn senior notes, due 2018 (c)		104				126
	GenOn senior notes, due 2020 (c)		71				81
	GenOn Americas Generation senior notes, due 2021 (c)		53				59
	GenOn Americas Generation senior notes, due 2031 (c)		35				37
	Total premium/(discount)		$	300			$	395
(a)	Discount of $1 million is related to current maturities in 2013 and 2012.
(b)	Discounts of $4 million and $5 million are related to current maturities in 2013 and 2012, respectively.
(c)	Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition, as described further in Note 3, Business Acquisitions and Dispositions.
NRG Recourse Debt
Senior Notes
Issuance of 2022 Senior Notes
On January 27, 2014, NRG issued $1.1 billion in aggregate principal amount at par of 6.25% senior notes due 2022. The notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is payable semi-annually beginning on July 15, 2014, until the maturity date of July 15, 2022. The proceeds were utilized to redeem the 8.5% and 7.625% 2019 Senior Notes, as described below, and are also expected to be utilized to fund the acquisition of EME.
In connection with the 2022 Senior Notes, NRG entered into a registration payment arrangement. For the first 90-day period immediately following a registration default, additional interest will be paid in an amount equal to 0.25% per annum of the principal amount of 2022 Senior Notes outstanding, as applicable. The amount of interest paid will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults are cured, up to a maximum amount of interest of 1.0% per annum of the principal amount of the 2022 Senior Notes outstanding, as applicable. The additional interest is paid on the next scheduled interest payment date and following the cure of the registration default, the additional interest payment will cease.
Redemption of 8.5% and 7.625% 2019 Senior Notes
On February 10, 2014, the Company redeemed $308 million of its 8.5% 2019 Senior Notes and $91 million of its 7.625% 2019 Senior Notes through a tender offer and call, at an average early redemption percentage of 106.992% and 105.500%, respectively. A $33 million loss on debt extinguishment of the 8.5% and 7.625% Senior Notes was recorded in the first quarter of 2014, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.
Redemption of Senior Notes
In 2012, the Company redeemed its $1.1 billion 2017 Senior Notes through a tender offer and call, at an average early redemption percentage of 104.016%. A $51 million loss on debt extinguishment of the 2017 Senior Notes was recorded, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.
In 2011, the Company redeemed its $1.2 billion Senior Notes due 2014 and its $2.4 billion Senior Notes due 2016 at an average redemption percentage of 102.007% and 103.868%, respectively, and recorded a loss on debt extinguishment of $28 million and $115 million, respectively, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.
Senior Notes Outstanding
As of December 31, 2013, NRG had six outstanding issuances of senior notes, or Senior Notes, under an Indenture, dated February 2, 2006, or the Indenture, between NRG and Law Debenture Trust Company of New York, as trustee:
(i.)8.500% senior notes, issued June 5, 2009 and due June 15, 2019, or the 2019 Senior Notes;
(ii.)8.250% senior notes, issued August 20, 2010 and due September 1, 2020, or the 2020 Senior Notes;
(iii.)7.625% senior notes, issued January 26, 2011 and due January 15, 2018, or the 2018 Senior Notes;
(iv.)7.625% senior notes, issued May 24, 2011 and due May 15, 2019, or the 7.625% 2019 Senior Notes;
(v.)7.875% senior notes, issued May 24, 2011 and due May 15, 2021, or the 2021 Senior Notes; and
(vi.)6.625% senior notes, issued September 24, 2012 and due March 15, 2023, or the 2023 Senior Notes.
The Company periodically enters into supplemental indentures for the purpose of adding entities under the Senior Notes as guarantors.
The Indentures and the form of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG. The Indentures also provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRG and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately. The terms of the Indentures, among other things, limit NRG's ability and certain of its subsidiaries' ability to return capital to stockholders, grant liens on assets to lenders and incur additional debt. Interest is payable semi-annually on the Senior Notes until their maturity dates.
Senior Notes Repurchases
On December 17, 2012, NRG entered into an agreement with a financial institution to repurchase up to $200 million of the Senior Notes in the open market by February 27, 2013.  In the first quarter of 2013, the Company paid $80 million, $104 million, and $42 million, at an average price of 114.179%, 111.700%, and 113.082% of face value, for repurchases of the Company's 2018 Senior Notes, 2019 Senior Notes and 2020 Senior Notes, respectively. A $28 million loss on the debt extinguishment of the 2018 Senior Notes, 2019 Senior Notes and 2020 Senior Notes was recorded during the three months ended March 31, 2013 which primarily consisted of the premiums paid on the repurchases and the write-off of previously deferred financing costs.
2019 Senior Notes
Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 104.25% of the note, plus interest payments due on the note from the date of redemption through June 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after June 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period	Redemption
	Percentage
June 15, 2014 to June 14, 2015	104.25	%
June 15, 2015 to June 14, 2016	102.83	%
June 15, 2016 to June 14, 2017	101.42	%
June 15, 2017 and thereafter	100	%
2020 Senior Notes
Prior to September 1, 2015, NRG may redeem all or a portion of the 2020 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the excess of the principal amount of the note over the following: the present value of 104.125% of the note, plus interest payments due on the note from the date of redemption through September 1, 2015, discounted at a Treasury rate plus 0.50%. In addition, on or after September 1, 2015, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period	Redemption
	Percentage
On or after September 1, 2015	104.125	%
On or after September 1, 2016	102.75	%
On or after September 1, 2017	101.375	%
September 1, 2018 and thereafter	100	%
2018 Senior Notes
Prior to maturity, NRG may redeem all or a portion of the 2018 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note or (ii) the excess of the present value of the principal amount at maturity plus all required interest payments due on the note through the maturity date discounted at a Treasury rate plus 0.50%.
7.625% 2019 Senior Notes
Prior to May 15, 2014, NRG may redeem up to 35% of the aggregate principal amount of the 7.625% 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.625% of the principal amount. Prior to May 15, 2014, NRG may redeem all or a portion of the 7.625% 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.813% of the note, plus interest payments due on the note from the date of redemption through May 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period	Redemption
	Percentage
May 15, 2014 to May 14, 2015	103.813	%
May 15, 2015 to May 14, 2016	101.906	%
May 15, 2016 and thereafter	100	%
2021 Senior Notes
Prior to May 15, 2016, NRG may redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.875% of the principal amount. Prior to May 15, 2016, NRG may redeem all or a portion of the 2021 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.938% of the note, plus interest payments due on the note from the date of redemption through May 15, 2016, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2016, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period	Redemption
	Percentage
May 15, 2016 to May 14, 2017	103.938	%
May 15, 2017 to May 14, 2018	102.625	%
May 15, 2018 to May 14, 2019	101.313	%
May 15, 2019 and thereafter	100	%
2023 Senior Notes
On September 24, 2012, NRG issued $990 million aggregate principal amount at par of 6.625% Senior Notes due 2023, or the 2023 Senior Notes. The 2023 Senior Notes were issued under the Indenture. The Indenture and the form of the notes provide, among other things, that the 2023 Senior Notes will be senior unsecured obligations of NRG. The proceeds, net of issuance costs, of $978 million for the 2023 Senior Notes were used to complete the tender offer of the 2017 Senior Notes.
Prior to September 15, 2015, NRG may redeem up to 35% of the aggregate principal amount of the 2023 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 106.625% of the principal amount. Prior to September 15, 2017, NRG may redeem all or a portion of the 2023 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on the note from the date of redemption through September 15, 2017, discounted at a Treasury rate plus 0.50%. In addition, on or after September 15, 2017, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period	Redemption
	Percentage
September 15, 2017 to September 14, 2018	103.313	%
September 15, 2018 to September 14, 2019	102.208	%
September 15, 2019 to September 14, 2020	101.104	%
September 15, 2020 and thereafter	100	%
In connection with the 2023 Senior Notes, NRG entered into a registration payment arrangement. For the first 90-day period immediately following a registration default, additional interest will be paid in an amount equal to 0.25% per annum of the principal amount of 2023 Senior Notes outstanding, as applicable. The amount of interest paid will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults are cured, up to a maximum amount of interest of 1.0% per annum of the principal amount of the 2023 Senior Notes outstanding, as applicable. The additional interest is paid on the next scheduled interest payment date and following the cure of the registration default, the additional interest payment will cease.
Senior Credit Facility
On June 4, 2013, NRG amended the Term Loan Facility to (i) obtain additional financing of $450 million, which was issued at a discount of 99.5%; and (ii) adjust the interest rate from LIBOR plus 2.50% to LIBOR plus 2.00%. In addition, the Company redeemed and re-issued $407 million of the Term Loan Facility to new lenders resulting in a $7 million loss on debt extinguishment, recorded during the second quarter 2013, which primarily consisted of the write-off of previously deferred financing costs and unamortized discount. The proceeds from the additional $450 million borrowed were used for general corporate purposes. Debt issuance costs of $23 million and a discount on debt issuance of $4 million will be amortized to interest expense through the maturity date of the Term Loan Facility. Repayments under the Term Loan Facility will consist of 0.25% per quarter, with the remainder due at maturity.
The Company also amended the Revolving Credit Facility to (i) increase the capacity by $211 million to a total of $2.5 billion; (ii) adjust the interest rate to LIBOR plus 2.25%; and (iii) extend the maturity date to July 1, 2018 to coincide with the maturity date of the Term Loan Facility. As a result of the amended Revolving Credit Facility, the Company capitalized debt issuance costs of $4 million, which will be amortized to interest expense through the maturity date of the Revolving Credit Facility. A $3 million loss on debt extinguishment was recorded during the three months ended June 30, 2013 related to the write-off of previously deferred financing costs. As of December 31, 2013, a total of $1.3 billion letters of credit were issued under the Revolving Credit Facility, with $1.2 billion remaining available to be issued. Commitment fees of 0.50% are charged on the unused portion of the Revolving Credit Facility.
The Senior Credit Facility replaced an existing senior credit facility in 2011, and NRG recorded a $32 million loss on extinguishment, which consisted of the write-off of previously deferred financing costs.
The Senior Credit Facility is guaranteed by substantially all of NRG's existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries, and certain other subsidiaries, including GenOn and its subsidiaries. The capital stock of these guarantor subsidiaries has been pledged for the benefit of the Senior Credit Facility's lenders.
The Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG's affiliates that have non-recourse debt financing, including GenOn and its subsidiaries, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG's foreign subsidiaries.
The Senior Credit Facility contains customary covenants, which, among other things, require NRG to meet certain financial tests, including minimum interest coverage ratio and a maximum leverage ratio on a consolidated basis, and limit NRG's ability to:
•	incur indebtedness and liens and enter into sale and lease-back transactions;
•	make investments, loans and advances; and
•	return capital to stockholders.
Interest Rate Swaps — 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. The Company pays 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 LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparty are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of the swaps, which matured on February 1, 2013, was $900 million with changes in the fair value through June 30, 2011 recorded in OCI and subsequent changes in the fair value reported in interest expense.
Fort Bend County Tax Exempt Bonds
On May 3, 2012, NRG executed a $54 million tax-exempt bond financing with a maturity date of May 1, 2038, issued by the Fort Bend County Industrial Development Corporation, or the Fort Bend County Tranche A Bonds. The Fort Bend County Tranche A Bonds will be used for the construction of a peaking unit with one or more components of a carbon capture system at the W.A. Parish Generating Station in Thompsons, TX, or W.A. Parish. The bonds initially bore weekly interest based on the SIFMA rate, and were enhanced by a letter of credit under the Company's Revolving Credit Facility covering amounts drawn. On October 18, 2012, NRG fixed the rate on the Fort Bend County Tranche A Bonds at 4.75% payable semiannually, and the letter of credit was canceled and replaced with an NRG guarantee. As of December 31, 2013 the full $54 million was drawn.
On October 18, 2012, NRG executed an additional $73 million tax-exempt bond financing, with a maturity date of November 1, 2042, also issued by the Fort Bend County Industrial Development Corporation, or the Fort Bend County Tranche B Bonds. The Fort Bend County Tranche B Bonds will be used for environmental and maintenance upgrades at W.A. Parish. The bonds were issued at a fixed rate of 4.75% payable semiannually, and are supported by an NRG guarantee. The proceeds drawn through December 31, 2013 were $12 million and the remaining balance will be drawn over time as qualifying expenditures are paid.
NRG Non-Recourse Debt
The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2013. All of NRG's non-recourse debt is secured by the assets in the respective GenOn subsidiaries and project subsidiaries as further described below. The net assets in the GenOn and project subsidiaries are subject to restrictions, including the ability to transfer assets out of the subsidiaries. As of December 31, 2013, NRG had net assets of $3.2 billion that were deemed restricted for purposes of Rule 4-08(e)(3)(iii) of Regulation S-X.
The indebtedness described below is non-recourse to NRG, unless otherwise noted.
GenOn Senior Notes
Under the GenOn Senior Notes and the related indentures, the GenOn Senior Notes are the sole obligation of GenOn and are not guaranteed by any subsidiary or affiliate of GenOn. The GenOn Senior Notes are senior unsecured obligations of GenOn having no recourse to any subsidiary or affiliate of GenOn. The GenOn Senior Notes restrict the ability of GenOn and its subsidiaries to encumber their assets. The GenOn Senior Notes are subject to acceleration of GenOn's obligations thereunder upon the occurrence of certain events of default, including: (a) default in interest payment for 30 days, (b) default in the payment of principal or premium, if any, (c) failure after 90 days of specified notice to comply with any other agreements in the indenture, (d) certain cross-acceleration events, (e) failure by GenOn or its significant subsidiaries to pay certain final and non-appealable judgments after 90 days and (f) certain events of bankruptcy and insolvency.
Redemption of 2014 GenOn Senior Notes
In June 2013, the Company redeemed all of the 2014 GenOn Senior Notes with an aggregate outstanding principal amount of $575 million at a redemption price of 106.778% of face value as well as any accrued and unpaid interest as of the redemption date. In connection with the redemption, an $11 million loss on the debt extinguishment of the 2014 GenOn Senior Notes was recorded during the three months ended June 30, 2013 which primarily consisted of a make whole premium payment offset by the write-off of unamortized premium.
The GenOn Senior Notes due 2014, which had a face value of $575 million, were recorded at their fair value of $618 million on the GenOn acquisition date. The related $43 million premium was being amortized to interest expense until the notes were redeemed in June 2013, as previously discussed.
2018 and 2020 GenOn Senior Notes
The GenOn Senior Notes due 2018 and 2020 and the related indentures restrict the ability of GenOn to incur additional liens and make certain restricted payments, including dividends. In the event of a default or if restricted payment tests are not satisfied, GenOn would not be able to distribute cash to its parent, NRG. At December 31, 2013, GenOn did not meet the consolidated debt ratio component of the restricted payments test and, therefore, the ability of GenOn to make restricted payments, including dividends, loans and advances to NRG, is limited to specified exclusions, including up to $250 million of such restricted payments. As of December 31, 2013, GenOn net assets of $0 billion were deemed restricted for purposes of Rule 4-08(e)(3)(iii) of Regulation S-X.
Prior to maturity, GenOn may redeem the senior notes due 2018, in whole or in part, at a redemption price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note.
Prior to October 15, 2015, GenOn may redeem the senior notes due 2020, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note. In addition, on or after October 15, 2015, GenOn may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption rate:
Redemption Period	Redemption
	Percentage
October 15, 2015 to October 14, 2016	104.938	%
October 15, 2016 to October 14, 2017	103.292	%
October 15, 2017 to October 14, 2018	101.646	%
October 15, 2018 and thereafter	100	%
The GenOn Senior Notes due 2018 and 2020, which have a face value of $675 million and $550 million, respectively, were recorded at their fair values of $802 million and $632 million, respectively, on the GenOn acquisition date. The $127 million and $82 million premiums are being amortized to interest expense over the life of the related notes.
2017 GenOn Senior Notes
Prior to maturity, GenOn may redeem all or a part of the GenOn Senior Notes due 2017 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note.
The GenOn Senior Notes due 2017, which have a face value of $725 million, were recorded at their fair value of $800 million, on the GenOn acquisition date. The $75 million premium is being amortized to interest expense over the life of the notes.
GenOn Americas Generation Senior Notes
The GenOn Americas Generation Senior Notes due 2021 and 2031 are senior unsecured obligations of GenOn Americas Generation, a wholly owned subsidiary of NRG, having no recourse to any subsidiary or affiliate of GenOn Americas Generation.
Prior to maturity, GenOn Americas Generation may redeem all or a part of the senior notes due 2021 and 2031 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) the discounted present value of the then-remaining scheduled payments of principal and interest on the outstanding notes, discounted at a Treasury rate plus 0.375%, less the unpaid principal amount; and (ii) zero.
The GenOn Americas Generation Senior Notes, which have a face value of $450 million and $400 million, respectively, were recorded at their fair values of $510 million and $437 million, respectively, on the GenOn acquisition date. The $60 million and $37 million premiums are being amortized to interest expense over the life of the related notes.
NRG Yield, Inc. Convertible Notes
On February 11, 2014, NRG Yield, Inc. closed on its offering of $300 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019, or the NRG Yield Senior Notes. The initial purchasers exercised their option to purchase up to an additional $45 million in aggregate principal amount of the NRG Yield Senior Notes. NRG Yield, Inc. expects to receive the proceeds in early March. The NRG Yield Senior Notes are convertible, under certain circumstances, into NRG Yield, Inc. common stock, cash or a combination thereof at an initial conversion price of $46.55 per Class A common share, which is equivalent to an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of NRG Yield Senior Notes. Interest on the NRG Yield Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2014. The NRG Yield Senior Notes will mature on February 1, 2019, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding August 1, 2018, the NRG Yield Senior Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date.
Project Financings
The following are descriptions of certain indebtedness of NRG's project subsidiaries that are outstanding as of December 31, 2013.
Dandan Financing
In December 2013, with respect to the Guam solar project, NRG, through its wholly-owned subsidiary, NRG Solar Dandan LLC, or Dandan, entered into a credit agreement with a bank, or the Dandan Financing Agreement, for a $81 million construction loan that converts to a term loan in September 2014 and a $23 million cash grant loan. The construction loans have interest rates of LIBOR plus an applicable margin of 2.25% or base rate plus 1.25% and the cash grant loans have an interest rate of LIBOR plus an applicable margin of 1.75%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.25%, which escalates 0.25% on the fifth, tenth, and fifteenth anniversary of the term conversion. The term loan, which is secured by all the assets of Dandan, matures on the 18th anniversary of the term conversion and amortizes based upon a predetermined schedule. The Dandan Financing Agreement also includes a letter of credit facility on behalf of Dandan of up to $5 million. Dandan pays an availability fee of 2.25% from the closing date until the 5th anniversary of the term conversion date and 2.50% from the 5th anniversary of the term conversion date on issued letters of credit. As of December 31, 2013, $19 million was outstanding under the term loan, and $5 million in letters of credit in support of the project were issued.
Kansas South Facility
In the second quarter of 2013, the Company, through its wholly owned subsidiary, NRG Solar PV LLC, acquired Kansas South, a 20 MW utility-scale photovoltaic solar facility located in Kings County, California, shortly before commercial operation. In June 2013, NRG recorded $59 million of non-recourse project level debt under the Kansas South Facility which includes a $38 million term loan due 2031 and a $21 million cash grant bridge loan due the earlier of 10 days after receipt of the cash grant or March 2014. The term loan has an interest rate of 3 month LIBOR plus an applicable margin of 2.625% and increases by 0.25% every four years. The cash grant bridge loan has an interest rate of 1 month LIBOR plus an applicable margin of 2.00%. The term loan amortizes on a predetermined schedule and is secured by all of the assets of Kansas South. As of December 31, 2013, $4 million of letters of credit were issued under the Kansas South Facility.
NRG Repowering Holdings LLC Facility
In June 2013, $82 million of letters of credit issued under the NRG Repowering Holdings LLC Facility were returned to the Company. In July 2013, the NRG Repowering Holding LLC Facility was terminated and the Company issued replacement letters of credit under its Revolving Credit Facility.
Marsh Landing Credit Agreement
In October 2010, Marsh Landing entered into a credit agreement for up to approximately $650 million of commitments to provide construction and permanent financing for the Marsh Landing generating facility. The credit facility consisted of a $155 million tranche A senior secured term loan facility, due 2017, a $345 million tranche B senior secured term loan facility, due 2023, a $50 million senior secured letter of credit facility to support debt service reserve requirements and a $100 million senior secured letter of credit facility to support collateral requirements under its PPA with PG&E. In May 2013, Marsh Landing met the conditions under the credit agreement to convert the construction loan for the facility to a term loan, which will amortize on a predetermined basis. Prior to term conversion, the Company drew the remaining funds available under the facility in order to pay costs due for construction. The Company issued a $24 million letter of credit under the facility in support of its debt service requirements. As of December 31, 2013, Marsh Landing had $473 million outstanding.
Avra Valley Financing
On August 30, 2012, NRG, through its subsidiary, NRG Solar Avra Valley LLC, or Avra Valley, entered into a credit agreement with a bank, or the Avra Valley Financing Agreement, for a $66 million construction loan that converted to a term loan in January 2013 and an $8 million cash grant loan. Both the construction and cash grant loans have interest rates of LIBOR plus an applicable margin of 2.25%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.25%, which escalates 0.25% on the fifth, tenth, and fifteenth anniversary of the term conversion. The term loan, which is secured by all the assets of Avra Valley, matures on the 18th anniversary of the term conversion and amortizes based upon a predetermined schedule. The cash grant was received and the cash grant loan was repaid in June 2013. The Avra Valley Financing Agreement also includes a letter of credit facility on behalf of Avra Valley of up to $4 million. Avra Valley pays an availability fee of 100% of the applicable margin on issued letters of credit. As of December 31, 2013, $63 million was outstanding under the term loan, and $4 million in letters of credit in support of the project were issued.
Alpine Financing
On March 16, 2012, NRG, through its wholly-owned subsidiary, NRG Solar Alpine LLC, or Alpine, entered into a credit agreement with a group of lenders, or the Alpine Financing Agreement, for a $166 million construction loan, which converted to a term loan in March 2013, and a $68 million cash grant loan. On January 15, 2013 the credit agreement was amended reducing the cash grant loan to $63 million.  The construction loan had an interest rate of LIBOR plus an applicable margin of 2.50% and the cash grant loan has an interest rate of 1 month LIBOR plus an applicable margin of 2.25%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.50%, which escalates 0.25% on the fifth anniversary of the term conversion. The term loan, which is secured by all the assets of Alpine, amortizes based upon a predetermined schedule with final maturity in November 2022. The Alpine Financing Agreement also includes a letter of credit facility on behalf of Alpine of up to $37 million. Alpine pays an availability fee of 100% of the applicable margin on issued letters of credit. As of December 31, 2013, $159 million was outstanding under the term loans, and $37 million in letters of credit in support of the project were issued. In January, 2014, the Company was awarded the full cash grant of $72 million as applied for, relating to the Alpine project, and has received the post-sequestration funds of $66 million, and subsequently repaid the balance of the cash grant loan.
High Desert Facility
In the first quarter of 2013, the Company, through its wholly owned subsidiary, NRG Solar PV LLC, acquired High Desert, a 20 MW utility-scale photovoltaic solar facility located in Lancaster, California, shortly before commercial operation.  As part of the acquisition of High Desert, NRG recorded $82 million of non-recourse project level debt in March 2013 issued under the High Desert Facility which is comprised of $53 million of fixed rate notes due 2033 at an interest rate of 5.15%, $7 million of floating rate notes due 2023, $22 million of bridge notes due the earlier of 10 days after receipt of the cash grant or May 2014 and a revolving facility of $12 million. The floating rate notes have an interest rate of 3 month LIBOR while the bridge notes have an interest rate of 1 month LIBOR plus 2.50%. The revolving facility can be used for cash or for the issuance of up to $9 million in letters of credit. As of December 31, 2013, $9 million of letters of credit were issued under the revolving facility.  The notes amortize on predetermined schedules and are secured by all of the assets of High Desert.
NRG Yield Revolving Credit Facility
In connection with the initial public offering of Class A common stock of NRG Yield, Inc. in July 2013, as further described in Note 1, Nature of Business, NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving credit facility, which provides a revolving line of credit of $60 million. The NRG Yield revolving credit facility can be used for cash or for the issuance of letters of credit. There was no cash drawn or letters of credit issued under the NRG Yield revolving credit facility as of December 31, 2013.
CVSR Financing
On September 30, 2011, NRG acquired CVSR, as discussed in Note 3, Business Acquisitions and Dispositions. In connection with the acquisition, High Plains Ranch II LLC, a wholly-owned subsidiary of NRG, entered into the CVSR Financing Agreement with the FFB, to borrow up to $1.2 billion to finance the costs of constructing this solar facility. The CVSR Financing Agreement, which matures in 2037, is non-recourse to NRG. Funding requests will be submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the CVSR Financing Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375%, and are secured by the assets of CVSR. As of December 31, 2013, $1,104 million was outstanding under the loan.
In January 2014, the U.S. Treasury Department awarded the Company cash grants for the CVSR project of $307 million, or $285 million net of sequestration, which was approximately 75% of the cash grant for which the Company had applied. NRG is evaluating the basis for the award and all of its options with respect to recovering the full amount of the award. Proceeds received in January 2014 were utilized to repay the borrowings due on February 5, 2014.
Under the terms of the CVSR Financing Agreement, on November 17, 2011, CVSR entered into a series of swaptions with a notional value of $686 million, or 80% of the guaranteed term loan amount, in order to hedge the project interest rate risk. These swaptions matured over a series of seven scheduled settlement dates to correspond with the completion dates of the project. As of December 31, 2013, all of the swaptions have expired.
NRG West Holdings Credit Agreement
On August 23, 2011, NRG, through its wholly-owned subsidiary, NRG West Holdings LLC, or West Holdings, entered into a credit agreement with a group of lenders in respect to the El Segundo Energy Center, or the West Holdings Credit Agreement. The West Holdings Credit Agreement, which establishes a $540 million, two tranche construction loan facility with additional facilities for the issuance of letters of credit or working capital loans, is secured by the assets of West Holdings.
The two tranche construction loan facility consists of the $480 million Tranche A Construction Facility, or the Tranche A Facility, and the $60 million Tranche B Construction Facility, or the Tranche B Facility. The Tranche A and Tranche B Facilities, which mature in August 2023, convert to a term loan and have an interest rate of LIBOR, plus an applicable margin which increases by 0.125% periodically from conversion through year eight for the Tranche A Facility and increases by 0.125% upon term conversion and on the third and sixth anniversary of the term conversion and by 0.250% on the eighth anniversary of the term conversion for the Tranche B Facility. The Tranche A and Tranche B Facilities amortize based upon a predetermined schedule over the term of the loan with the balance payable at maturity.
The West Holdings Credit Agreement also provides for the issuance of letters of credit and working capital loans to support the El Segundo Energy Center collateral needs. This includes letter of credit facilities on behalf of West Holdings of up to $90 million in support of the PPA, up to $48 million in support of the collateral agent, and a working capital facility which permits loans or the issuance of letters of credit of up to $10 million.
As of December 31, 2013, under the West Holdings Credit Agreement, West Holdings borrowed $480 million under the Tranche A Facility, $32 million under the Tranche B Facility, issued a $33 million letter of credit in support of the PPA, and issued a $1 million letter of credit under the working capital facility.
Agua Caliente Financing
On August 5, 2011, NRG acquired Agua Caliente, as discussed in Note 3, Business Acquisitions and Dispositions.  In connection with the acquisition, Agua Caliente Solar LLC, a wholly-owned subsidiary of NRG, entered into the Agua Caliente Financing Agreement with the FFB, to borrow up to $967 million to finance the costs of constructing this solar facility.  The Agua Caliente Financing Agreement, which matures in 2037, is non-recourse to NRG. Funding requests will be submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the Agua Caliente Financing Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375%, and are secured by the assets of Agua Caliente.  As of December 31, 2013, $878 million had been drawn under this agreement.
Ivanpah Financing
On April 5, 2011, NRG acquired a majority interest in Ivanpah, as discussed in Note 3, Business Acquisitions and Dispositions. On April 5, 2011, Ivanpah entered into the Ivanpah Credit Agreement with the FFB to borrow up to $1.6 billion to finance the costs of constructing the Ivanpah solar facilities. Each phase of the project is governed by a separate financing agreement and is non-recourse to both the other projects and to NRG. Funding requests are submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE.   Amounts borrowed under the Ivanpah Credit Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375% and are secured by all the assets of Ivanpah. On February 27, 2014, Solar Partners II received an extension with respect to its borrowings previously due in 2014, which are subsequently due in 2015. Solar Partners II intends to submit an application to the U.S. Department of Treasury for a cash grant; any proceeds received will be utilized to repay the borrowings that mature in 2015.
The following table reflects the borrowings under the Ivanpah Credit Agreement as of December 31, 2013:
	Maximum borrowings available under Ivanpah Credit Agreement				Amounts borrowed				Weighted average interest rate on amounts borrowed
	(In millions, except rates)
Solar Partners I, due June 27, 2014 (a)	$	159			$	159			1.68	%
Solar Partners I, due June 27, 2033	392				371				2.808	%
Solar Partners II, due February 27, 2014 (a)	132				132				1.611	%
Solar Partners II, due February 27, 2038	387				377				3.132	%
Solar Partners VIII, due October 27, 2014 (a)	117				116				1.998	%
Solar Partners VIII, due October 27, 2038	440				420				3.097	%
	$	1,627			$	1,575
(a)	The cash portion of the loan is fully drawn; additional amounts will be utilized for capitalized interest.
Peakers
In June 2002, NRG Peaker Finance Company LLC, or Peakers, an indirect wholly-owned subsidiary of NRG, issued $325 million in floating rate bonds due June 2019. Peakers subsequently swapped such floating rate debt for fixed rate debt at an all-in cost of 6.67% per annum. Principal, interest, and swap payments were originally guaranteed by Syncora Guarantee Inc., successor in interest to XL Capital Assurance, through a financial guaranty insurance policy. In 2009, Assured Guaranty Mutual Corp assumed the responsibility as the bond insurer and controlling party. Syncora Guarantee Inc. continues to be the swap insurer. These notes are also secured by, among other things, substantially all of the assets of and membership interests in Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC, and NRG Rockford Equipment LLC. As of December 31, 2013, $165 million in principal remained outstanding on these bonds. Upon emergence from bankruptcy, NRG issued a $36 million letter of credit to Peakers' collateral agent. The letter of credit may be drawn if the project is unable to meet principal or interest payments. There are no provisions requiring NRG to replenish the letter of credit if it is drawn. On December 10, 2012, the collateral agent drew the remaining $4 million on the letter of credit, and NRG contributed $19 million in equity to Peakers to meet its debt service requirements. On December 10, 2013, NRG contributed an additional $32 million in equity to Peakers to meet its debt service requirements. As of December 31, 2013, nothing remains available for additional letters of credit issuances.
On February 21, 2014, NRG Peaker Finance Company LLC elected to redeem approximately $30 million of the outstanding bonds at a redemption price equal to the principal amount plus a redemption premium, accrued and unpaid interest, and other fees, totaling approximately $35 million in connection with the removal of Bayou Cove Peaking Power LLC from the peaker financing collateral package, which also involved limited commitments for certain repairs on other assets that were funded concurrently with the making of the December 10, 2013 debt service payment. The removal of Bayou Cove Peaking Power LLC from the collateral package provides the Company flexibility on future transactions with respect to this asset.
Interest Rate Swaps — Project Financings
Many of NRG's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap payments by the project subsidiary and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The following table summarizes the swaps, some of which are forward starting as indicated, related to NRG's project level debt as of December 31, 2013.
Non-Recourse Debt	% of Principal			Fixed Interest Rate			Floating Interest Rate		Notional Amount at		Effective Date	Maturity Date
									31-Dec-13
									(In millions)
NRG Peaker Finance Co. LLC	100	%		6.673	%		3-mo. LIBOR + 1.07%		$	165	18-Jun-02	10-Jun-19
NRG West Holdings LLC	75	%		2.417	%		3-mo. LIBOR		405		30-Nov-11	31-Aug-23
South Trent Wind LLC	75	%		3.265	%		3-mo. LIBOR		51		June 15, 2010	June 14, 2020
South Trent Wind LLC	75	%		4.95	%		3-mo. LIBOR		21		June 30, 2020	June 14, 2028
NRG Solar Roadrunner LLC	75	%		4.313	%		3-mo. LIBOR		33		September 30, 2011	December 31, 2029
NRG Solar Alpine LLC	85	%		2.744	%		3-mo. LIBOR		135		December 31, 2012	December 31, 2029
NRG Solar Avra Valley LLC	90	%		2.333	%		3-mo. LIBOR		56		November 30, 2012	November 30, 2030
NRG Marsh Landing	75	%		3.244	%		3-mo. LIBOR		472		June 28, 2013	June 30, 2023
Other	75	%		various			various		104		various	various
Consolidated Annual Maturities
Annual payments based on the maturities of NRG's debt, for the years ending after December 31, 2013, are as follows:
	(In millions)
2014	$	1,045
2015	254
2016	270
2017	1,034
2018	4,035
Thereafter	10,166
Total	$	16,804

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	NRG's AROs are primarily related to the future dismantlement of equipment on leased property and environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities. In addition, NRG has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations.
	See Note 6, Nuclear Decommissioning Trust Fund, for a further discussion of NRG's nuclear decommissioning obligations. Accretion for the nuclear decommissioning ARO and amortization of the related ARO asset are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income, consistent with regulatory treatment.
	The following table represents the balance of ARO obligations as of December 31, 2013, and 2012, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2013:
		(In millions)
	Balance as of December 31, 2012	$	646
	Revisions in estimates for current obligations	(77		)
	Additions	29
	Spending for current obligations	(5		)
	Accretion — Expense	19
	Accretion — Nuclear decommissioning	17
	Balance as of December 31, 2013	$	629

Benefit_Plans_and_Other_Postre

Benefit Plans and Other Postretirement Benefit Plans (Notes)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Benefit Plans and Other Postretirement Benefits	'
	Benefit Plans and Other Postretirement Benefits
	NRG sponsors and operates defined benefit pension and other postretirement plans. As part of the GenOn acquisition, discussed in Note 3, Business Acquisitions and Dispositions, NRG assumed GenOn's defined benefit pension plans and other postretirement benefit plans, and GenOn's benefit plan obligations were recorded at fair value at the time of the acquisition. NRG expects to contribute $78 million to the Company's pension plans in 2014.
	NRG pension benefits are available to eligible non-union and union employees through various defined benefit pension plans. These benefits are based on pay, service history and age at retirement. Most pension benefits are provided through tax-qualified plans. Certain executive pension benefits that cannot be provided by the tax-qualified plans are provided through unfunded non-tax-qualified plans. NRG also provides postretirement health and welfare benefits for certain groups of employees. Cost sharing provisions vary by the terms of any applicable collective bargaining agreements.
	As part of the change in control associated with the GenOn acquisition, NRG has decided to terminate/settle the nonqualified legacy GenOn Benefit Restoration Plan and Supplemental Executive Retirement Plan. Final settlement payments totaling $12 million will be paid to remaining participants in the first quarter of 2014.
	NRG Defined Benefit Plans
	The annual net periodic benefit cost related to NRG's pension and other postretirement benefit plans include the following components:
		Year Ended December 31,
		Pension Benefits
		2013				2012				2011
		(In millions)
	Service cost benefits earned	$	30			$	14			$	14
	Interest cost on benefit obligation	47				23				21
	Expected return on plan assets	(55		)		(23		)		(21		)
	Amortization of unrecognized net loss	9				4				—
	Curtailment	(1		)		—				—
	Net periodic benefit cost	$	30			$	18			$	14
		Year Ended December 31,
		Other Postretirement Benefits
		2013				2012				2011
		(In millions)
	Service cost benefits earned	$	4			$	2			$	2
	Interest cost on benefit obligation	9				6				6
	Amortization of unrecognized net loss	—				1				—
	Net periodic benefit cost	$	13			$	9			$	8
	A comparison of the pension benefit obligation, other postretirement benefit obligations and related plan assets for NRG's plans on a combined basis is as follows:
		As of December 31,
		Pension Benefits								Other Postretirement
										Benefits
		2013				2012				2013			2012
		(In millions)
	Benefit obligation at January 1	$	1,147			$	456			$	220		$	122
	Obligations assumed in the GenOn acquisition	—				596				—			87
	Service cost	30				14				4			2
	Interest cost	47				23				9			6
	Plan amendments	5				—				(4		)	(1		)
	Actuarial (gain)/loss	(125		)		75				(29		)	6
	Employee and retiree contributions	—				—				2			1
	Benefit payments	(43		)		(17		)		(11		)	(3		)
	Curtailment	(1		)		—				—			—
	Benefit obligation at December 31	1,060				1,147				191			220
	Fair value of plan assets at January 1	757				308				—			—
	Assets acquired in the GenOn acquisition	—				402				—			—
	Actual return on plan assets	116				41				—			—
	Employee contributions	—				—				2			1
	Employer contributions	50				23				9			2
	Benefit payments	(43		)		(17		)		(11		)	(3		)
	Fair value of plan assets at December 31	880				757				—			—
	Funded status at December 31 — excess of obligation over assets	$	(180	)		$	(390	)		$	(191	)	$	(220	)
	Amounts recognized in NRG's balance sheets were as follows:
		As of December 31,
		Pension Benefits								Other Postretirement
										Benefits
		2013				2012				2013			2012
		(In millions)
	Current liabilities	$	12			$	1			$	9		$	9
	Non-current liabilities	166				389				182			211
	Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows:
		As of December 31,
		Pension Benefits								Other Postretirement
										Benefits
		2013				2012				2013			2012
		(In millions)
	Unrecognized (gain)/loss	$	(57	)		$	140			$	(12	)	$	17
Prior service cost/(credit)	4				(2		)		(6		)	(2		)
Other changes in plan assets and benefit obligations recognized in OCI were as follows:
	Year Ended December 31,
	Pension								Other Postretirement
	Benefits								Benefits
	2013				2012				2013			2012
	(In millions)
Unrecognized (gain)/loss	$	(188	)		$	56			$	(29	)	$	7
Amortization of net actuarial gain	(9		)		(4		)		—			(1		)
Prior service credit	5				—				(4		)	(1		)
Curtailment	1				—				—			—
Total recognized in other comprehensive loss	$	(191	)		$	52			$	(33	)	$	5
Total recognized in net periodic pension cost and other comprehensive income	$	(161	)		$	71			$	(20	)	$	13
The Company's estimated unrecognized gain and unrecognized prior service cost for NRG's pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is approximately $5 million. The Company's estimated unrecognized gain and unrecognized prior service cost for NRG's postretirement plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is $2 million.
The following table presents the balances of significant components of NRG's pension plan:
	As of December 31,
	Pension Benefits
	2013				2012
	(In millions)
Projected benefit obligation	$	1,060			$	1,147
Accumulated benefit obligation	967				1,024
Fair value of plan assets	880				757
NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows:
	Fair Value Measurements as of December 31, 2013
	Quoted Prices in				Significant				Total
	Active Markets for				Observable Inputs
	Identical Assets				(Level 2)
	(Level 1)
	(In millions)
Common/collective trust investment — U.S. equity	—				370				370
Common/collective trust investment — non-U.S. equity	—				212				212
Common/collective trust investment — fixed income	—				296				296
Short-term investment fund	2				—				2
Total	$	2			$	878			$	880
	Fair Value Measurements as of December 31, 2012
	Quoted Prices in				Significant				Total
	Active Markets for				Observable Inputs
	Identical Assets				(Level 2)
	(Level 1)
	(In millions)
U.S. equity investment	$	—			$	26			$	26
Non-U.S. equity investment	24				44				68
Corporate bond investment — fixed income	—				32				32
Common/collective trust investment — U.S. equity	—				290				290
Common/collective trust investment — non-U.S. equity	—				111				111
Common/collective trust investment — fixed income	—				228				228
Short-term investment fund	—				2				2
Total	$	24			$	733			$	757
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the U.S. and non-U.S. equity investments and the corporate bond investment is based on quoted prices in active markets, and is categorized as Level 1. All equity investments are valued at the net asset value of shares held at year end. The fair value of the corporate bond investment is based on the closing price reported on the active market on which the individual securities are traded. The fair value of the common/collective trusts is valued at fair value which is equal to the sum of the market value of all of the fund's underlying investments, and is categorized as Level 2. There are no investments categorized as Level 3.
The following table presents the significant assumptions used to calculate NRG's benefit obligations:
	As of December 31,
	Pension Benefits						Other Postretirement Benefits
Weighted-Average Assumptions	2013			2012			2013			2012
Discount rate	4.99	%		4.16	%		5.06	%		4.31	%
Rate of compensation increase	3.65	%		3.57	%		N/A			N/A
Health care trend rate	—			—			8.5% grading to			8.0% grading to
							5.5% in 2019			5.0% in 2019
The following table presents the significant assumptions used to calculate NRG's benefit expense:
	As of December 31,
	Pension Benefits									Other Postretirement Benefits
Weighted-Average Assumptions	2013			2012			2011			2013		2012			2011
Discount rate	4.16	%		4.95	%		5.47	%		4.31	%	5.15	%		5.77	%
Expected return on plan assets	7.12	%		6.96	%		7.34	%		—		—			—
Rate of compensation increase	3.57	%		4.34	%		4.4	%		—		—			—
Health care trend rate	—			—			—			8.3% grading to		8.0% grading to			8.0% grading to
										5.3% in 2019		5.0% in 2019			5.0% in 2019
NRG uses December 31 of each respective year as the measurement date for the Company's pension and other postretirement benefit plans. The Company sets the discount rate assumptions on an annual basis for each of NRG's retirement related benefit plans at their respective measurement date. This rate is determined by NRG's Investment Committee based on information provided by the Company's actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. The discount rate assumptions used to determine the future pension obligation as of December 31, 2013, 2012 and 2011 were based on the Aon Hewitt AA Above Median, or AAM, yield curve, which was designed by Aon Hewitt to provide a means for corporate plan sponsors to value the liabilities of defined pension benefit and other post retirement benefit plans. The AAM is a hypothetical Aa yield curve represented by a series of annualized individual discount rates from 0.5 to 99 years. Each bond issue is required to have an average rating of AA, when averaging all available ratings by Moody's Investor Services, Standard & Poor's and Fitch.
NRG employs a total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The Investment Committee reviews the asset mix periodically and as the plan assets increase in future years, the Investment Committee may examine other asset classes such as real estate or private equity. NRG employs a building block approach to determining the long-term rate of return for plan assets, with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed income are preserved, consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonableness and appropriateness.
The target allocations of NRG's pension plan assets were as follows for the years ended December 31, 2013 and 2012:
U.S. equity	38.5 - 45.5%
Non-U.S. equity	16.5 - 28%
U.S. fixed income	30 - 45%
Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. equities, as well as among growth, value, small and large capitalization stocks.
NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows:
					Other Postretirement Benefit
	Pension				Benefit Payments				Medicare Prescription Drug Reimbursements
	Benefit Payments
	(In millions)
2014	$	60			$	9			$	—
2015	53				10				—
2016	58				10				—
2017	59				10				—
2018	63				11				—
2019-2023	362				62				2
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:
	1-Percentage-				1-Percentage-
	Point Increase				Point Decrease
	(In millions)
Effect on total service and interest cost components	$	1			$	(1	)
Effect on postretirement benefit obligation	14				(11		)
STP Defined Benefit Plans
NRG has a 44% undivided ownership interest in STP, as discussed further in Note 27, Jointly Owned Plants. STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. For the years ending December 31, 2013 and 2012, NRG reimbursed STPNOC $14 million and $15 million, respectively, towards its defined benefit plans. In 2014, NRG expects to reimburse STPNOC $18 million for its contributions towards the plans.
The Company has recognized the following in its statement of financial position, statement of operations and accumulated OCI related to its 44% interest in STP:
	As of December 31,
	Pension Benefits								Other Postretirement Benefits
	2013				2012				2013			2012
	(In millions)
Funded status — STPNOC benefit plans	$	(42	)		$	(76	)		$	(52	)	$	(56	)
Net periodic benefit costs	11				10				8			8
Other changes in plan assets and benefit obligations recognized in other comprehensive income	(31		)		14				(10		)	1
Defined Contribution Plans
NRG's employees are also eligible to participate in defined contribution 401(k) plans.  Upon completion of the GenOn acquisition, NRG assumed GenOn's defined contribution 401(k) plans and amended the plan covering the majority of employees with NRG 401(k) plan features, effective January 1, 2013. On July 5, 2013, the GenOn defined contribution 401(k) plans were merged into the NRG 401(k) plan.
The Company's contributions to these plans were as follows:
	Year Ended December 31,
	2013				2012 (a)				2011
	(In millions)
Company contributions to defined contribution plans	$	34			$	24			$	24
(a)	Includes contributions to former GenOn plans for the period of December 15, 2012 to December 31, 2012.

Capital_Structure_Notes

Capital Structure (Notes)	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Capital Structure	'
	Capital Structure
	For the period from December 31, 2010 to December 31, 2013, the Company had 10,000,000 shares of preferred stock authorized, 500,000,000 shares of common stock authorized and 250,000 shares of preferred stock issued and outstanding. The following table reflects the changes in NRG's common shares issued and outstanding for each period presented:
		Common
		Issued		Treasury			Outstanding
	Balance as of December 31, 2010	304,006,027		(56,808,672	)		247,197,355
	Shares issued under ESPP	—		120,127			120,127
	Shares issued from LTIP	177,693		—			177,693
	Share repurchases	—		(19,975,654	)		(19,975,654	)
	Balance as of December 31, 2011	304,183,720		(76,664,199	)		227,519,521
	Shares issued under ESPP	—		158,481			158,481
	Shares issued under LTIPs	996,262		—			996,262
	Shares issued through GenOn acquisition	93,932,634		—			93,932,634
	Balance as of December 31, 2012	399,112,616		(76,505,718	)		322,606,898
	Shares issued under ESPP	—		130,482			130,482
	Shares issued under LTIPs	2,014,164		—			2,014,164
	Share repurchases	—		(972,292	)		(972,292	)
	Balance as of December 31, 2013	401,126,780		(77,347,528	)		323,779,252
	Common Stock
	The following table summarizes NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plans as of December 31, 2013:
	Equity Instrument	Common Stock
		Reserve Balance
	3.625% Convertible perpetual preferred	16,000,000
	Long-term incentive plans	21,121,160
	Total	37,121,160
	Common stock dividends — NRG paid its first quarterly dividend on the Company's common stock of $0.09 per share, or $0.36 per share on an annualized basis, on August 15, 2012. In 2013, the Company increased its annual common stock dividend by 33% to $0.48 per share. The following table lists the dividends paid per common share during 2013 and 2012:
		First Quarter			Second Quarter				Third Quarter		Fourth Quarter
	2013	$	0.09		$	0.12			$	0.12	$	0.12
	2012	$	—		$	—			$	0.09	$	0.09
	On February 17, 2014, NRG paid a quarterly dividend on the Company's common stock of $0.12 per share.
	Employee Stock Purchase Plan — Under the ESPP eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at 85% of its fair market value on the exercise date. An exercise date occurs each June 30 and December 31. As of December 31, 2013, there remained 888,388 shares of treasury stock reserved for issuance under the ESPP, and in the first quarter of 2014, 71,478 shares of common stock were issued to employee accounts from treasury stock.
	2013 Capital Allocation Program — The Company was authorized to repurchase $200 million of its common stock in 2013 under the 2013 Capital Allocation Program. During the first quarter, the Company purchased 972,292 shares of NRG common stock for approximately $25 million at an average cost of $25.88 per share. As a result of the proposed acquisition of EME, the Company did not complete the remaining $175 million of share repurchases under the 2013 Capital Allocation Program.
	Preferred Stock
	3.625% Redeemable Preferred Stock
	On August 11, 2005, NRG issued 250,000 shares of 3.625% Convertible Perpetual Preferred Stock, or 3.625% Preferred Stock, which is treated as Redeemable Preferred Stock, to the Credit Suisse Group in a private placement. The 3.625% Preferred Stock amount is located after the liabilities but before the stockholders' equity section on the balance sheet, due to the fact that the preferred shares can be redeemed in cash by the stockholder. The 3.625% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 3.625% Preferred Stock are entitled to receive, out of legally available funds, cash dividends at the rate of 3.625% per annum, or $36.25 per share per year, payable in cash quarterly in arrears commencing on December 15, 2005.
	Each share of the 3.625% Preferred Stock is convertible during the 90-day period beginning August 11, 2015, at the option of NRG or the holder. Holders tendering the 3.625% Preferred Stock for conversion shall be entitled to receive, for each share of 3.625% Preferred Stock converted, $1,000 in cash and a number of shares of NRG common stock equal in value to the product of (a) the greater of (i) the difference between the average closing share price of NRG common stock on each of the twenty consecutive scheduled trading days starting on the date thirty exchange business days immediately prior to the conversion date, or the Market Price, and $29.54 and (ii) zero, times (b) 50.77. The number of shares of NRG common stock to be delivered under the conversion feature is limited to 16,000,000 shares. If upon conversion, the Market Price is less than $19.69, then the Holder will deliver to NRG cash or a number of shares of NRG common stock equal in value to the product of (i) $19.69 minus the Market Price, times (ii) 50.77. NRG may elect to make a cash payment in lieu of delivering shares of NRG common stock in connection with such conversion, and NRG may elect to receive cash in lieu of shares of common stock, if any, from the Holder in connection with such conversion. The conversion feature is considered an embedded derivative per ASC 815 that is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815.
	If a fundamental change occurs, the holders will have the right to require NRG to repurchase all or a portion of the 3.625% Preferred Stock for a period of time after the fundamental change at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends. The 3.625% Preferred Stock is senior to all classes of common stock, and junior to all of the Company's existing and future debt obligations and all of NRG subsidiaries' existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries.

Investments_Accounted_for_by_t

Investments Accounted for by the Equity Method and Variable Interest Entities (Notes)	12 Months Ended
	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]	'
Investments Accounted for by the Equity Method and Variable Interest Entities	'
	Investments Accounted for by the Equity Method and Variable Interest Entities
	NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates, as well as other adjustments.
	The following table summarizes NRG's equity method investments as of December 31, 2013:
	Name	Geographic Area	Economic
			Interest
	Avenal Solar Holdings LLC	United States	50	%
	GenConn Energy LLC	United States	50	%
	Saguaro Power Company	United States	50	%
	Sherbino I Wind Farm LLC	United States	50	%
	Texas Coastal Ventures, LLC	United States	50	%
	Sabine CoGen, LP	United States	50	%
	Sunora Energy Solutions I LLC	United States	50	%
	Gladstone Power Station	Australia	37.5	%
		As of December 31,
		2013			2012
		(In millions)
	Undistributed earnings from equity investments	$	94		$	149
	Variable Interest Entities
	NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, but NRG is not the primary beneficiary, under the equity method.
	GenConn Energy LLC — NRG owns a 50% interest in GenConn, a limited liability company formed to construct, own and operate two 190MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. Each of these facilities was constructed pursuant to 30-year cost of service type contracts with the Connecticut Light & Power Company. All four units at the GenConn Devon facility reached commercial operation in 2010 and were released to the ISO-NE by July 2010. In June 2011, the GenConn Middletown facility reached commercial operation and was released to the ISO-NE. The project was funded through equity contributions from the owners and non-recourse, project level debt. As of December 31, 2013, NRG had a $118 million equity investment in GenConn. NRG's maximum exposure to loss is limited to its equity investment.
	In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the working capital facility. In March 2012, the working capital facility was amended to $35 million. On September 17, 2013, GenConn refinanced its existing project financing facility. The refinanced facility is comprised of a $237 million note with an interest rate of 4.73% and a maturity date of July 2041 and a 5-year, $35 million working capital facility which can be used to issue letters of credit at an interest rate of 1.875%. The refinancing is secured by all of the GenConn assets.
	As discussed in Note 21, Related Party Transactions, in 2010 and 2011, NRG earned revenues from construction management agreements with Devon and Middletown and interest income from a note receivable with GenConn.
	Sherbino I Wind Farm LLC — NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. Sherbino is a 150 MW wind farm, which commenced commercial operations in October 2008. In December 2008, Sherbino entered into a 15-year term loan facility which is non-recourse to NRG. As of December 31, 2013, the outstanding principal balance of the term loan facility was $114 million, and is secured by substantially all of Sherbino's assets and membership interests. NRG's maximum exposure to loss is limited to its equity investment, which was $87 million as of December 31, 2013.
	Texas Coastal Ventures, LLC — NRG owns a 50% interest in Texas Coastal Ventures, LLC, or TCV, a joint venture with Hilcorp Energy I, L.P., through its subsidiary Petra Nova LLC. Texas Coastal Ventures was formed by Petra Nova and Hilcorp for the purpose of using carbon dioxide captured from flue gas from certain of NRG's coal-generating power plants in the United States Gulf Coast in an enhanced oil recovery process. TCV is managed by the joint venture participants and operated by Hilcorp. TCV entered into service agreements with Petra Nova LLC, which include a management services agreement for the operation and management of the joint venture's pipeline assets, as well as a CO2 supply agreement having an initial term of twenty years. NRG's maximum exposure to loss is limited to its equity investment, which was $63 million as of December 31, 2013.
	Other Equity Investments
	Gladstone — Through a joint venture, NRG owns a 37.5% interest in Gladstone, a 1,613 megawatt coal-fueled power generation facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants in proportion to their ownership interests. Coal is sourced from local mines in Queensland. NRG and the joint venture participants receive their respective share of revenues directly from the off takers in proportion to the ownership interests in the joint venture. Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold to the Queensland Government owned utility under long term supply contracts. The Company recorded an impairment loss for Gladstone in the fourth quarter of 2013 of $92 million, as described in Note 10, Asset Impairments. NRG's investment in Gladstone was $188 million as of December 31, 2013.

Segment_Reporting_Notes

Segment Reporting (Notes)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Reporting	'
	Segment Reporting
	Effective June 2013, the Company's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are primarily segregated based on the Retail Business, conventional power generation, alternative energy businesses, NRG Yield, and corporate activities.  Within NRG's conventional power generation, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, East, South Central, West and Other, which includes international businesses and maintenance services.  The Company's alternative energy segment includes solar and wind assets (excluding those in the NRG Yield segment), electric vehicle services and the carbon capture business.  NRG Yield includes certain of the Company's contracted generation assets including three natural gas or dual-fired facilities, eight utility-scale solar and wind generation facilities, two portfolios of distributed solar facilities and thermal infrastructure assets. Intersegment sales are accounted for at market.
	For the years ended December 31, 2013, 2012, and 2011, there were no customers from whom the Company derived more than 10% of the Company's consolidated revenues.
		Year Ended December 31, 2013
					Conventional Power Generation
		Retail			Texas			East			South			West			Other			Alternative Energy			NRG Yield			Corporate			Eliminations			Total
											Central
		(In millions)
	Operating revenues(a)	$	6,241		$	2,106		$	3,209		$	874		$	475		$	153		$	233		$	313		$	7		$	(2,316	)	$	11,295
	Operating expenses	5,535			1,826			2,512			750			318			144			147			134			50			(2,307		)	9,109
	Depreciation and amortization	142			457			320			98			55			4			108			51			21			—			1,256
	Impairment charges	—			—			459			—			—			—			—			—						—			459
	Acquisition-related transaction and integration costs	—			—			—			—			—			—			—			—			128			—			128
	Operating income/(loss)	564			(177		)	(82		)	26			102			5			(22		)	128			(192		)	(9		)	343
	Equity in earnings/(loss) of unconsolidated affiliates	—			—			—			4			(11		)	6			(4		)	22			—			(10		)	7
	Impairment losses on investments	—			—			—			—			—			(99		)	—			—			—			—			(99		)
	Other income, net	—			1			28			1			1			3			2			2			74			(99		)	13
	Loss on debt extinguishment	—			—			—			—			—			—			—			—			(50		)	—			(50		)
	Interest expense	(2		)	(1		)	(85		)	(18		)	(14		)	—			(57		)	(35		)	(735		)	99			(848		)
	Income/(loss) before income taxes	562			(177		)	(139		)	13			78			(85		)	(81		)	117			(903		)	(19		)	(634		)
	Income tax (benefit)/expense	—			—			—			—			—			(29		)	—			8			(261		)	—			(282		)
	Net income/(loss)	$	562		$	(177	)	$	(139	)	$	13		$	78		$	(56	)	$	(81	)	$	109		$	(642	)	$	(19	)	$	(352	)
	Less: Net income attributable to noncontrolling interest	$	—		$	—		$	—		$	—		$	—		$	—		$	27		$	13		$	—		$	(6	)	$	34
	Net income/(loss) attributable to NRG Energy, Inc.	$	562		$	(177	)	$	(139	)	$	13		$	78		$	(56	)	$	(108	)	$	96		$	(642	)	$	(13	)	$	(386	)
	Balance sheet
	Equity investments in affiliates	—			—			5			17			(35		)	188			150			227			—			(99		)	453
	Capital expenditures(a)	30			119			181			88			136			15			818			116			73						1,576
	Goodwill	260			1,713			—			—			—			—			12			—			—			—			1,985
	Total assets	4,717			11,656			8,437			2,431			1,638			468			6,213			2,313			25,290			(29,261		)	33,902
	(b) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	9		$	2,058		$	87		$	16		$	4		$	64		$	23		$	—		$	7
	(a) Includes accruals.
		Year Ended December 31, 2012
					Conventional Power Generation
		Retail			Texas			East(d)			South(d)Central			West(d)			Other			Alternative Energy			NRG Yield			Corporate(d)			Eliminations			Total
		(In millions)
	Operating revenues(c)	$	5,772		$	2,074		$	854		$	807		$	259		$	173		$	125		$	175		$	17		$	(1,834	)	$	8,422
	Operating expenses	5,065			1,712			754			695			194			161			87			119			47			(1,819		)	7,015
	Depreciation and amortization	162			458			137			93			12			2			49			25			12			—			950
	Acquisition-related transaction and integration costs	—			—			—			—			—			—			—			—			107			—			107
	Operating income/(loss)	545			(96		)	(37		)	19			53			10			(11		)	31			(149		)	(15		)	350
	Equity in earnings/(loss) of unconsolidated affiliates	—			—			—			—			7			13			—			19			(2		)	—			37
	Impairment losses on investments	—			—			—			—			—			—			—			—			(2		)	—			(2		)
	Bargain purchase gain related to GenOn acquisition	—			—			—			—			—			—			—			—			296			—			296
	Other income, net	—			2			2			1			1			4			—			1			26			(18		)	19
	Loss on debt extinguishment	—			—			—			—			—			—			—			—			(51		)	—			(51		)
	Interest expense	(4		)	—			(20		)	(18		)	(2		)	(3		)	(26		)	(28		)	(578		)	18			(661		)
	Income/(loss) before income taxes	541			(94		)	(55		)	2			59			24			(37		)	23			(460		)	(15		)	(12		)
	Income tax expense/(benefit)	—			—			—			—			—			3			—			10			(340		)	—			(327		)
	Net income/(loss)	541			(94		)	(55		)	2			59			21			(37		)	13			(120		)	(15		)	315
	Less: Net income attributable to noncontrolling interest	—			—			—			—			—			—			20						—			—			20
	Net income/(loss) attributable to NRG Energy, Inc.	$	541		$	(94	)	$	(55	)	$	2		$	59		$	21		$	(57	)	$	13		$	(120	)	$	(15	)	$	295
	Balance sheet
	Equity investments in affiliates	$	—		$	—		$	7		$	19		$	27		$	322		$	163		$	220		$	10		$	(92	)	$	676
	Capital expenditures (e)	19			117			71			36			244			16			2,700			478			12			—			3,693
	Goodwill	231			1,713			—			—			—			—			12			—			—			—			1,956
	Total assets	$	3,122		$	10,988		$	6,972		$	1,935		$	1,313		$	442		$	5,367		$	1,964		$	28,330		$	(25,450	)	$	34,983
	(c) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	5		$	1,657		$	73		$	—		$	—		$	69		$	20		$	—		$	10
	(d) Includes GenOn results for the period December 15, 2012 to December 31, 2012.
	(e) Includes accruals.
		Year Ended December 31, 2011
					Conventional Power Generation
		Retail(f)(g)			Texas(f)			East(f)			South(f)			West(f)			Other(f)			Alternative Energy(f)			NRG Yield(f)			Corporate(f)			Eliminations			Total
											Central
				(In millions)
Operating revenues	$	5,642		$	2,832		$	924		$	817		$	149		$	183		$	22		$	164		$	11		$	(1,665	)	$	9,079
Operating expenses	5,113			1,910			859			703			92			178			62			114			30			(1,673		)	7,388
Depreciation and amortization	159			463			118			89			10			—			23			22			12			—			896
Impairment losses	—			160			—			—			—			—			—						—			—			160
Operating income/(loss)	370			299			(53		)	25			47			5			(63		)	28			(31		)	8			635
Equity in earnings of unconsolidated affiliates	—			—			—			—			9			9			4			13			—			—			35
Impairment losses on investments	—			—			—			—			—			—			—			—			(495		)	—			(495		)
Other income, net	—			1			2			2			—			5			3			2			21			(17		)	19
Loss on debt extinguishment	—			—			—			—			—			—			—			—			(175		)	—			(175		)
Interest (expense)/income	(4		)	16			(47		)	(41		)	(2		)	(6		)	(7		)	(19		)	(571		)	16			(665		)
Income/(loss) before income taxes	366			316			(98		)	(14		)	54			13			(63		)	24			(1,251		)	7			(646		)
Income tax (benefit)/expense	(3		)	—			—			—			—			—			—			9			(847		)	(2		)	(843		)
Net income/(loss)	369			316			(98		)	(14		)	54			13			(63		)	15			(404		)	9			197
(f) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	5		$	1,586		$	43		$	—		$	—		$	25		$	23		$	—		$	—
(g) Includes Green Mountain Energy results and Energy Plus results for the period October 1, 2011 to December 31, 2011.

Earnings_Per_Share_Notes

Earnings Per Share (Notes)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	(Loss)/Earnings Per Share
	Basic (loss)/earnings per common share is computed by dividing net (loss)/income less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted (loss)/earnings per share is computed in a manner consistent with that of basic (loss)/earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.
	Dilutive effect for equity compensation and other equity instruments — The outstanding non-qualified stock options, non-vested restricted stock units, deferred stock units, market stock units and performance units are not considered outstanding for purposes of computing basic (loss)/earnings per share. However, these instruments are included in the denominator for purposes of computing diluted (loss)/earnings per share under the treasury stock method. The if-converted method is used to determine the dilutive effect of embedded derivatives in the Company's 3.625% Preferred Stock.
	The reconciliation of NRG's basic (loss)/earnings per share to diluted (loss)/earnings per share is shown in the following table:
		Year Ended December 31,
		2013				2012			2011
		(In millions, except per share amounts)
	Basic (loss)/earnings per share attributable to NRG common stockholders
	Net (loss)/income attributable to NRG Energy, Inc.	$	(386	)		$	295		$	197
	Dividends for preferred shares	9				9			9
	(Loss)/Income Available to Common Stockholders	$	(395	)		$	286		$	188
	Weighted average number of common shares outstanding	323				232			240
	(Loss)/Earnings per weighted average common share — basic	$	(1.22	)		$	1.23		$	0.78
	Diluted (loss)/earnings per share attributable to NRG common stockholders
	Weighted average number of common shares outstanding	323				232			240
	Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—				2			1
	Total dilutive shares	323				234			241
	(Loss)/Earnings per weighted average common share — diluted	$	(1.22	)		$	1.22		$	0.78
	The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted (loss)/earnings per share:
		Year Ended December 31,
		2013			2012			2011
		(In millions of shares)
	Equity compensation	9			8			7
	Embedded derivative of 3.625% redeemable perpetual preferred stock	16			16			16
	Total	25			24			23

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	The income tax provision from continuing operations consisted of the following amounts:
		Year Ended December 31,
		2013			2012			2011
		(In millions, except percentages)
	Current
	U.S. Federal	$	—		$	—		$	(538	)
	State	11			20			10
	Foreign	—			13			16
	Total — current	11			33			(512		)
	Deferred
	U.S. Federal	(207		)	(326		)	(317		)
	State	(57		)	(24		)	(5		)
	Foreign	(29		)	(10		)	(9		)
	Total — deferred	(293		)	(360		)	(331		)
	Total income tax benefit	$	(282	)	$	(327	)	$	(843	)
	Effective tax rate	44.5		%	2,725.00		%	130.5		%
	The following represents the domestic and foreign components of loss before income tax benefit:
		Year Ended December 31,
		2013			2012			2011
		(In millions)
	U.S.	$	(549	)	$	(41	)	$	(680	)
	Foreign	(85		)	29			34
	Total	$	(634	)	$	(12	)	$	(646	)
	A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate is as follows:
		Year Ended December 31,
		2013			2012			2011
		(In millions, except percentages)
	Loss Before Income Taxes	$	(634	)	$	(12	)	$	(646	)
	Tax at 35%	(222		)	(4		)	(226		)
	State taxes, including change in rate, net of federal benefit	11			1			15
	Foreign operations	5			(24		)	(3		)
	Federal and state tax credits	(36		)	(158		)	(1		)
	Valuation allowance	(5		)	5			(63		)
	Expiration/utilization of capital losses	10			—			45
	Reversal of valuation allowance on expired/utilized capital losses	(10		)	—			(45		)
	Impact of non-taxable equity earnings	(14		)	(7		)	—
	Bargain purchase gain related to GenOn acquisition	—			(104		)	—
	Foreign earnings	—			—			4
	Interest accrued on uncertain tax positions	(3		)	2			2
	Production tax credit	(14		)	(14		)	(14		)
	Reversal of uncertain tax position reserves	(11		)	(13		)	(561		)
	Tax expense attributable to consolidated partnerships	8			—			—
	Other	(1		)	(11		)	4
	Income tax benefit	$	(282	)	$	(327	)	$	(843	)
	Effective income tax rate	44.5		%	2,725.00		%	130.5		%
	For the year ended December 31, 2013, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to generation of ITCs from the Company's Agua Caliente solar project in Arizona of $36 million and production tax credits, or PTCs, generated from certain Texas wind facilities of $14 million.
	For the year ended December 31, 2012, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of ITCs from the Company's Agua Caliente solar project in Arizona of $158 million, a benefit of $104 million resulting from the gain on bargain purchase of GenOn, and PTCs generated from certain Texas wind facilities of $14 million.
	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 temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:
		As of December 31,
		2013			2012
		(In millions)
	Deferred tax liabilities:
	Emissions allowances	$	15		$	15
	Difference between book and tax basis of property	22			123
	Derivatives, net	334			323
	Goodwill	191			165
	Cumulative translation adjustments	9			19
	Intangibles amortization (excluding goodwill)	—			85
	Investment in projects	540			52
	Other	—			—
	Total deferred tax liabilities	1,111			782
Deferred tax assets:
Deferred compensation, pension, accrued vacation and other reserves	203			232
Discount/premium on notes	111			156
Differences between book and tax basis of contracts	285			343
Pension and other postretirement benefits	168			274
Equity compensation	57			57
Bad debt reserve	18			14
U.S. capital loss carryforwards	1			1
U.S. Federal net operating loss carryforwards	1,381			605
Foreign net operating loss carryforwards	77			89
State net operating loss carryforwards	161			89
Foreign capital loss carryforwards	1			1
Deferred financing costs	3			33
Federal and state tax credits	308			258
Federal benefit on state uncertain tax positions	23			18
Intangibles amortization (excluding goodwill)	20			—
Other	23			7
Total deferred tax assets	2,840			2,177
Valuation allowance	(291		)	(191		)
Total deferred tax assets, net of valuation allowance	2,549			1,986
Net deferred tax asset	$	1,438		$	1,204
The following table summarizes NRG's net deferred tax position:
	As of December 31,
	2013			2012
	(In millions)
Net deferred tax asset — current	$	258		$	56
Net deferred tax asset — noncurrent	1,202			1,203
Net deferred tax liability — noncurrent	$	(22	)	$	(55	)
Net deferred tax asset	$	1,438		$	1,204
Deferred tax assets and valuation allowance
Net deferred tax balance — As of December 31, 2013, and 2012, NRG recorded a net deferred tax asset of $1.4 billion and $1.2 billion, respectively. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in our estimate of future taxable income, we considered the profit before tax generated in recent years. Based on our assessment of positive and negative evidence, including available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $291 million and $191 million of tax assets as of December 31, 2013 and 2012, respectively, thus a valuation allowance has been recorded. The Company estimates it will need to generate future taxable income of approximately $3.1 billion, to fully realize the net federal deferred tax asset before expiration commencing in 2026.
In connection with the accounting for the GenOn acquisition, the Company recorded the realizable deferred tax assets and liabilities acquired, primarily consisting of net operating losses and other temporary differences. In addition, the excess of GenOn's historical tax basis of assets and liabilities over the amount assigned to the fair value of the assets acquired and liabilities assumed generated deferred tax assets and liabilities that were recorded on the acquisition date.
NOL carryforwards — At December 31, 2013, the Company had tax effected cumulative domestic NOLs consisting of carryforwards for federal income tax purposes of $1.4 billion and state of $161 million. In addition, NRG has cumulative foreign NOL carryforwards of $77 million of which $4 million will expire through 2016 and of which $73 million do not have an expiration date.
Valuation allowance — As of December 31, 2013, the Company's tax effected valuation allowance was $291 million, consisting of $216 million for state deferred tax assets, primarily operating loss carryovers, and $75 million for foreign deferred tax assets, primarily operating loss carryovers for which there is insufficient earnings to support future realization.
Taxes Receivable and Payable
As of December 31, 2013, NRG recorded a current tax payable of $12 million that represents a tax liability due for domestic state taxes of $11 million, as well as foreign taxes payable of $1 million. NRG has a domestic tax receivable of $551 million, of which $539 million relates to federal cash grants applied for eligible solar energy projects net of sequestration of $42 million; the balance of $12 million is related to federal refunds anticipated from multiple income tax carry-back claims to prior tax years. In addition, a $65 million non-current receivable has been established relating to property tax refunds due to the New York State Empire Zone program generated in years 2010 through 2013.
Uncertain tax benefits
NRG has identified uncertain tax benefits whose after-tax value was $115 million that if recognized, would impact the Company's income tax expense.
As of December 31, 2013, and 2012, NRG has recorded a non-current tax liability of $61 million and $72 million, respectively. As of December 31, 2012 and 2011, the balance primarily related to positions taken on various state returns, including accrued interest.
The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the year ended December 31, 2013, the Company recognized a benefit of $5 million in interest and penalties and accrued interest of $2 million. For the year ended December 31, 2012, the Company accrued interest of $3 million. As of December 31, 2013, and 2012, NRG had cumulative interest and penalties related to these uncertain tax benefits of $14 million and $15 million, respectively.
Tax jurisdictions — 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 Australia.
Prior to the GenOn acquisition in December 2012, the Company was not subject to U.S. federal income tax examinations for years prior to 2007. GenOn is no longer subject to U.S. federal income tax examinations for years prior to 2010. With few exceptions, state and local income tax examinations are no longer open for years before 2007. The Company's significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2008.
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.
The following table reconciles the total amounts of uncertain tax benefits:
	As of December 31,
	2013			2012
	(In millions)
Balance as of January 1	$	193		$	178
Increase due to current year positions	2			21
Decrease due to current year positions	—			(3		)
Increase due to prior year positions	4			13
Decrease due to prior year positions	(40		)	(21		)
Increase due to acquisitions	—			5
Decrease due to settlements and payments	(44		)	—
Uncertain tax benefits as of December 31	$	115		$	193

StockBased_Compensation_Notes

Stock-Based Compensation (Notes)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation [Abstract]	'
Stock-Based Compensation	'
	Stock-Based Compensation
	NRG Energy, Inc. Long-Term Incentive Plan
	As of December 31, 2013, and 2012, a total of 22,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP, subject to adjustments in the event of reorganization, recapitalization, stock split, reverse stock split, stock dividend, and a combination of shares, merger or similar change in NRG's structure or outstanding shares of common stock. There were 7,238,065 and 7,580,318 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 2013, and 2012, respectively.
	GenOn Acquisition
	Effective December 14, 2012, in connection with the GenOn acquisition, as discussed in Note 3, Business Acquisitions and Dispositions, NRG assumed the GenOn Energy, Inc. 2010 Omnibus Incentive Plan, and the name was changed to the NRG 2010 Stock Plan for GenOn Employees, or the NRG GenOn LTIP. As of December 31, 2013, 5,558,390 shares of NRG common stock were authorized for issuance under the NRG GenOn LTIP, and there were 1,053,485 shares of common stock remaining available for grants under the NRG GenOn LTIP. In addition, NRG assumed certain other terminated GenOn plans, under which NRG will not grant any further awards. All outstanding awards under the NRG GenOn LTIP and the terminated plans were appropriately adjusted based on the Exchange Ratio, and remain subject to the terms and conditions of the applicable plans prior to the acquisition.
	In addition, upon completion of the GenOn acquisition, the following occurred to GenOn's outstanding stock-based incentive awards: (i) each outstanding and unvested RSU that was granted under the GenOn plans before 2012 vested in full and was exchanged for shares of NRG common stock in the acquisition based on the Exchange Ratio; (ii) each outstanding and unvested GenOn NQSO that was granted under the GenOn plans before 2012 vested in full and converted into an option to purchase NRG common stock; (iii) each outstanding and unvested RSU that was granted under the GenOn plans in 2012, was converted into an unvested RSU of NRG, and (iv) each outstanding and unvested GenOn NQSO that was granted under the GenOn plans during 2012 was converted into an NQSO to purchase NRG common stock on the same vesting schedule.
	Under the acquisition method of accounting, GenOn employee NQSOs and RSUs which vested upon close of the acquisition were measured and recorded at acquisition-date fair value, resulting in additional purchase price consideration of $28 million. As of December 14, 2012, unvested NQSOs that were converted to options to purchase NRG common stock and RSUs that were converted to NRG RSUs were recorded in NRG's consolidated balance sheet.
	Non-Qualified Stock Options
	NQSOs granted under the NRG LTIP and the NRG GenOn LTIP typically have three-year graded vesting schedules beginning on the grant date and become exercisable at the end of the requisite service period. NRG recognizes compensation costs for NQSOs over the requisite service period for the entire award. The maximum contractual term is ten years for 2.8 million of NRG's outstanding NQSOs, and six years for the remaining 1.2 million NQSOs. No NQSOs were granted in 2013.
	The following table summarizes the Company's NQSO activity and changes during the year:
		Shares			Weighted Average			Weighted Average Remaining Contractual Term (In years)		Aggregate Intrinsic Value
					Exercise Price					(In millions)
		(In whole)
	Outstanding at December 31, 2012	6,677,885			$	28.85		4		$	17
	Forfeited	(1,044,902	)		27.75
	Exercised	(1,656,002	)		14.28
	Outstanding at December 31, 2013	3,976,981			35.2			2		17
	Exercisable at December 31, 2013	3,592,810			31.8			2		13
	The following table summarizes the weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from the exercises of options:
		Year Ended December 31,
		2013				2012			2011
		(In millions, except for weighted average)
	Weighted average grant date fair value per option granted	$	—			$	—		$	8.73
	Total intrinsic value of options exercised	19				0.3			0.2
	Cash received from options exercised	33				1			2
	Restricted Stock Units
	As of December 31, 2013, RSUs granted under the Company's LTIPs fully vest three years from the date of issuance. Fair value of the RSUs is based on the closing price of NRG common stock on the date of grant. The following table summarizes the Company's non-vested RSU awards and changes during the year:
		Units			Weighted Average Grant-Date Fair Value per Unit
		(In whole)
	Non-vested at December 31, 2012	2,608,551			$	21.28
	Granted	617,009			23.37
	Forfeited	(322,448	)		21.34
	Vested	(879,933	)		22.64
	Non-vested at December 31, 2013	2,023,179			21.22
	The total fair value of RSUs vested during the years ended December 31, 2013, 2012, and 2011, was $22 million, $18 million and $2 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2013, 2012, and 2011 was $23.37, $17.90, and $22.78, respectively.
	Deferred Stock Units
	DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established under the terms of the award. DSUs granted under the Company's LTIPs are fully vested at the date of issuance. Fair value of the DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in the period of grant.
	The following table summarizes the Company's outstanding DSU awards and changes during the year:
		Units			Weighted Average Grant-Date Fair Value per Unit
		(In whole)
	Outstanding at December 31, 2012	697,515			$	20.91
	Granted	205,667			23.18
	Conversions (a)	(524,636	)		22.55
	Outstanding at December 31, 2013	378,546			19.78
	(a) 52,864 Deferred Stock Units were converted to cash for the year ended December 31, 2013.
	The aggregate intrinsic values for DSUs outstanding as of December 31, 2013, 2012, and 2011 were approximately $7 million, $15 million, and $8 million respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2013, 2012, and 2011 were $12 million, $1.4 million and $0.4 million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2013, 2012, and 2011 was $23.18, $16.33 and $24.31, respectively.
	Market Stock Units
	MSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's Total Shareholder Return, or TSR. Each MSU represents the potential to receive NRG common stock after the completion of three years of service from the date of grant. The number of shares of NRG common stock to be paid (if any) as of the vesting date for each MSU will depend on the TSR. The number of shares of common stock to be paid as of the vesting date for each MSU is equal to: (i) one half of one share of common stock if the TSR has decreased by no more than 50% of the value of the common stock on the date of grant; (ii) one share of common stock, if the TSR equals the value of the common stock on the date of grant; and (iii) two shares of common stock if the TSR is 200% or greater of the value of the common stock on the date of grant. If the TSR is less than 50% of the value of the common stock on the date of grant, no common stock will be paid. If the TSR is between 50% and 200%, shares awarded are interpolated. The value of the common stock on the date of grant is based on the 20-day average of the common stock closing price.
	The following table summarizes the Company's non-vested MSU awards and changes during the year:
		Units			Weighted Average Grant-Date Fair Value per Unit
		(in whole)
	Non-vested at December 31, 2012	1,003,920			$	22.43
	Granted	1,066,626			27.46
	Vested	(20,000	)		26.64
	Forfeited	(214,040	)		24.16
	Non-vested at December 31, 2013	1,836,506			24.72
	The weighted average grant date fair value of MSUs granted during the years ended December 31, 2013, 2012 and 2011, was $27.46, $22.11 and $27.59, respectively.
	The fair value of MSUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period. Significant assumptions used in the fair value model with respect to the Company's MSUs are summarized below:
		2013			2012
	Expected volatility	27.12%-29.11%			29.60%-35.98%
	Expected term (in years)	3			3
	Risk free rate	0.37%-0.59%			0.29%-0.40%
	For the years ended December 31, 2013 and 2012, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the MSU, which equals the vesting period.
Performance Units
PUs granted under the Company's LTIP fully vest three years from the date of issuance. PUs are paid out upon vesting if the Measurement Price is equal to or greater than Threshold Price. The Threshold Price, Target Price and Maximum Price are determined on the date of issuance. The payout for each PU will be equal to: (i) a pro-rata amount between 0.5 and 1 share of common stock, if the Measurement Price is equal to or greater than the target Threshold Price but less than the Target Price; (ii) one share of common stock, if the Measurement Price equals the Target Price; (iii) a pro-rata amount between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price; and (iv) two shares of common stock, if the Measurement Price is equal to, or greater than, the Maximum Price.
The following table summarizes the Company's non-vested PU awards and changes during the year:
	Outstanding			Weighted Average Grant-Date Fair Value per Unit
	Units
	(In whole)
Non-vested at December 31, 2012	647,200			$	21.88
Vested	(36,700	)		19.89
Forfeited	(296,200	)		23.28
Non-vested at December 31, 2013	314,300			20.8
The weighted average grant date fair value of PUs granted during the year ended December 31, 2011 was $20.80. No PUs were granted in 2013 or 2012.
The fair value of PUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period.
Supplemental Information
The following table summarizes NRG's total compensation expense recognized for the years presented as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2013, for each of the five types of awards issued under the LTIPs. Minimum tax withholdings of $13 million, $6 million, and $1 million for the years ended December 31, 2013, 2012, and 2011, respectively, are reflected as a reduction to Additional Paid-in Capital on the Company's Consolidated Balance Sheet, and are reflected as operating activities on the Company's Consolidated Statement of Cash Flows.
											Non-vested Compensation Cost
	Compensation Expense										Unrecognized		Weighted Average Recognition Period Remaining (In years)
											Total Cost
	Year Ended December 31										As of December 31
Award	2013				2012			2011			2013		2013
	(In millions, except weighted average data)
NQSOs	$	4			$	6		$	8		$	1	1.1
RSUs	18				21			12			18		1.4
DSUs	2				2			2			—		0
MSUs	14				7			—			28		1.7
PUs	2				4			5			—		0
Total	$	40			$	40		$	27		$	47
Tax detriment recognized	$	(12	)		$	8		$	1

Related_Party_Transactions_Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	The following table summarizes NRG's material related party transactions with affiliates that are included in the Company's operating revenues, operating costs and other income and expense:
		Year Ended December 31,
		2013		2012		2011
		(In millions)
	Revenues from Related Parties Included in Operating Revenues
	Gladstone	$	6	$	7	$	7
	GenConn (a)	5		6		3
	Total	$	11	$	13	$	10
	Interest income from Related Parties Included in Other Income and Expense
	GenConn (a)	$	—	$	—	$	1
	Kraftwerke Schkopau GBR (b)	—		2		4
	Total	$	—	$	2	$	5
	(a)	The period in 2011 is from January 1, 2011 to June 30, 2011.
	(b)	The period in 2012 is from January 1, 2012 to July 17, 2012.
	Gladstone — NRG provides services to Gladstone, an equity method investment, under an operations and maintenance agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant as approved in the annual budget, as well as, a base monthly fee.
	GenConn — NRG has O&M agreements with GenConn Devon and GenConn Middletown that began in June 2011. Under a construction management agreement with GenConn, NRG had received fees for management, design and construction services. The construction at GenConn was completed in June 2011. In addition, NRG entered into a loan agreement with GenConn during 2009, pursuant to which it received interest income, which was converted into equity during 2011. See further discussion in Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities.
	Kraftwerke Schkopau GBR — SEG had a loan agreement with Kraftwerke Schkopau GBR, a partnership between Saale Energie GmbH and E.ON Kraftwerke GmbH, pursuant to which NRG received interest income. On July 17, 2012, the Company completed the sale of its 100% interest in Saale Energie GmbH, as discussed in Note 3, Business Acquisitions and Dispositions.
	Conemaugh and Keystone facilities — The Company operates the Conemaugh and Keystone facilities under five-year agreements that expire in December 2015 that, subject to certain provisions and notifications, could be terminated annually with one year's notice. The Company is reimbursed by the other owners for the cost of direct services provided to the Conemaugh and Keystone facilities. Additionally, the Company received fees of $10 million during 2013 and $1 million in 2012 subsequent to the GenOn acquisition. These fees, which are recorded in O&M expense in the consolidated statements of operations, are primarily to cover NRG REMA LLC's administrative support costs of providing these services.

Commitments_and_Contingencies_

Commitments and Contingencies (Notes)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Operating Lease Commitments
	GenOn Mid-Atlantic Leases
	The Company leases a 100% interest in the Dickerson and Morgantown coal generation units and associated property through 2029 and 2034, respectively, through its indirect subsidiary, GenOn MidAtlantic, LLC. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. As further described in Note 3, Business Acquisitions and Dispositions, in connection with the acquisition of GenOn, the Company recorded the out-of-market value as a liability in out-of-market contracts of $604 million. The liability will be amortized through rent expense on a straight-line basis over the term of the lease. The Company expects to record lease expense, net of amortization of the out-of-market liability, of approximately $44 million per year through the term of the lease.
	Future minimum lease commitments under the GenOn Mid-Atlantic operating leases for the years ending after December 31, 2013, are as follows:
	Period	(In millions)
	2014	$	131
	2015	110
	2016	150
	2017	144
	2018	105
	Thereafter	686
	Total	$	1,326
	REMA Leases
	The Company, through its indirect subsidiary, NRG REMA, LLC, leases a 100% interest in the Shawville coal generation facility through 2026 and leases 16.5% and 16.7% interest in the Keystone and Conemaugh coal generation facilities through 2034, and expects to make payments under the lease through 2029. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. As further described in Note 3, Business Acquisitions and Dispositions, in connection with the acquisition of GenOn, the Company recorded the out-of-market value as a liability in out-of-market contracts of $186 million. The liability will be amortized through rent expense on a straight-line basis over the term of the lease. The Company expects to record lease expense, net of amortization of the out-of-market liability, of approximately $33 million per year through the term of the lease.
	During 2011, GenOn completed an analysis of the cost of environmental controls required for the Shawville generating facility, including the installation of cooling towers. After evaluation of the forecasted energy and capacity prices, expected capital expenditures, operating costs, property taxes and other factors, GenOn concluded that the forecasted returns on investments necessary to comply with the environmental regulations are insufficient. Accordingly, NRG plans to place the coal-fired units at the Shawville generating facility in a long-term protective layup in April 2015. Under the lease agreement for Shawville, NRG's obligations generally are to pay the required rent and to maintain the leased assets in accordance with the lease documentation, including in compliance with prudent competitive electric generating industry practice and applicable laws. NRG will continue to evaluate options under the lease, including termination of the lease for economic obsolescence and/or keeping the facility in long-term protective layup during the term of the lease, or continuing operations with a different fuel.
	Future minimum lease commitments under the REMA operating leases for the years ending after December 31, 2013, are as follows:
	Period	(In millions)
	2014	$	63
	2015	56
	2016	61
	2017	63
	2018	55
	Thereafter	400
	Total	$	698
	Other Operating Leases
	NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2041. NRG also has certain tolling arrangements to purchase power which qualifies as operating leases. Certain operating lease agreements over their lease term include provisions such as scheduled rent increases, leasehold incentives, and rent concessions. The Company recognizes the effects of these scheduled rent increases, leasehold incentives, and rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was$88 million, $67 million, and $81 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	Future minimum lease commitments under operating leases for the years ending after December 31, 2013, are as follows:
	Period	(In millions)
	2014	$	79
	2015	78
	2016	63
	2017	41
	2018	38
	Thereafter	138
	Total (a)	$	437
	(a) Amounts in the table exclude future sublease income of $20 million associated with GenOn's long-term lease for its corporate headquarters in Houston, Texas.
	Coal, Gas and Transportation Commitments
	NRG has entered into long-term contractual arrangements to procure fuel and transportation services for the Company's generation assets and for the years ended December 31, 2013, 2012, and 2011, the Company purchased $2.8 billion, $1.4 billion, and $1.6 billion, respectively, under such arrangements.
	As of December 31, 2013, the Company's commitments under such outstanding agreements are estimated as follows:
	Period	(In millions)
	2014	$	963
	2015	272
	2016	254
	2017	220
	2018	136
	Thereafter	719
	Total	$	2,564
	Purchased Power Commitments
	NRG has purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities and do not qualify as operating leases. These contracts are not included in the consolidated balance sheet as of December 31, 2013. Minimum purchase commitment obligations are as follows as of December 31, 2013:
	Period	(In millions)
	2014	$	24
	2015	18
	2016	12
	2017	10
	2018	1
	Thereafter	—
	Total (a)	$	65
	(a)	As of December 31, 2013, the maximum remaining term under any individual purchased power contract is five years.
	Lignite Contract with Texas Westmoreland Coal Co.
	The lignite used to fuel the Texas region's Limestone facility is obtained from the Jewett mine, a surface mine adjacent to the Limestone facility, under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is based on a cost-plus arrangement with incentives and penalties to ensure proper management of the mine. NRG has the flexibility to increase or decrease lignite purchases from the mine within certain ranges, including the ability to suspend or terminate lignite purchases with adequate notice. The mining period extends through 2018 with an option to further extend the mining period by two five-year intervals.
	TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, NRG will be responsible for final mine reclamation obligations. The Railroad Commission of Texas has imposed a bond obligation of $107.5 million on TWCC for the reclamation of this lignite mine. Pursuant to the contract with TWCC, NRG supports this obligation as follows: $76 million is guaranteed by NRG Energy, Inc., and $31.5 million is supported by surety bonds posted by NRG. Additionally, NRG is required to provide additional performance assurance over TWCC's current bond obligations if required by the Railroad Commission of Texas.
	First Lien Structure
NRG has granted first liens to certain counterparties on substantially all of the Company's assets, excluding assets acquired in the GenOn acquisition, 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. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of December 31, 2013, the first lien exposure of net out-of-the-money positions to counterparties on hedges was $61 million.
Nuclear Insurance
STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Amendment to the Energy Policy Act of 2005, referred to as the Price-Anderson Act. Effective September 30, 2013, the current liability limit per incident was $13.6 billion, subject to change to account for the effects of inflation and the number of licensed reactors. An inflation adjustment must be made at least once every five years with the most recent adjustment effective September 2013. Under the Price-Anderson Act, owners of nuclear power plants in the U.S. are required to purchase primary insurance limits of $375 million for each operating site. In addition, the Price-Anderson Act requires an additional layer of protection through mandatory participation in a retrospective rating plan for power reactors resulting in an additional $13.2 billion in funds available for public liability claims. The current maximum assessment per incident, per reactor, is approximately $127 million, taking into account a 5% adjustment for administrative fees, payable at no more than $19 million per year, per reactor. NRG would be responsible for 44% of the maximum assessment, or $8 million per year, per reactor, and a maximum of $112 million per incident. In addition, the U.S. Congress retains the ability to impose additional financial requirements on the nuclear industry to pay liability claims that exceed $13.6 billion for a single incident. The liabilities of the co-owners of STP with respect to the retrospective premium assessments for nuclear liability insurance are joint and several.
STP purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Limited, or NEIL, an industry mutual insurance company, of which STP is a member. STP has purchased $2.75 billion in limits for nuclear events and $1.5 billion in limits for non-nuclear events, the maximum available from NEIL. The upper $1 billion in limits (excess of the first $1.75 billion in limits) is a single limit blanket policy shared with two Diablo Canyon nuclear reactors, which have no affiliation with the Company. This shared limit is not subject to automatic reinstatement in the event of a loss. The NEIL policy covers both nuclear and non-nuclear property damage events, and includes coverage for six weeks of lost revenue following a property damage event, at a weekly indemnity limit of $4 million, subject to a seventeen week waiting period. NRG also purchased an Accidental Outage policy from NEIL, which provides protection for lost revenue due to an insurable event. This coverage allows for reimbursement up to $1.98 million per week per unit up to a maximum of $215.6 million nuclear and $144 million non-nuclear, and is subject to an eight week waiting period. Under the terms of the NEIL policies, member companies may be assessed up to ten times their annual premium if the NEIL Board of Directors determines their surplus has been depleted due to the payment of property losses at any of the licensed reactors in a single policy year. NEIL requires that its members maintain an investment grade credit rating or insure their annual retrospective obligation by providing a financial guarantee, letter of credit, deposit premium, or an insurance policy. NRG has purchased an insurance policy from NEIL to guarantee the Company's obligation; however this insurance will only respond to retrospective premium adjustments assessed within twenty-four months after the policy term, whereas NEIL's Board of Directors can make such an adjustment up to six years after the policy expires.
Contingencies
The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
California Department of Water Resources
This matter concerned, among other contracts and other defendants, CDWR and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit.
On December 19, 2006, the Ninth Circuit decided that in FERC's review of the contracts at issue, FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress.
This matter was extensively litigated and on March 22, 2012, NRG reached an agreement in principle with the CPUC to settle and resolve this matter, including all related claims, on behalf of NRG and on behalf of Dynegy. The settlement agreement contains three material elements to be fulfilled over a four to six year period, depending upon several factors. First, the settlement agreement includes a $20 million cash payment due 30 days after FERC approval. Second, it includes the construction and operation of a fee-based charging network, to be owned and operated by NRG subsidiary, eVgo, which will consist of at least 200 publicly available fast-charging electric vehicle stations installed at locations across California. Last, it calls for the wiring and associated work required to improve at least 10,000 individual parking spaces to allow for the charging of electric vehicles in at least 1,000 multi-family complexes, worksites, and public interest locations such as community colleges, public universities, and public or non-profit hospitals. Although these improved newly wired parking spaces will continue to be owned by the local property owner, eVgo will have an 18-month exclusive right to obtain customers from these locations starting from the date of each completed installation. The expected $20 million cash payment was accrued and expensed in the statement of operations for the three months ended March 31, 2012. In addition, the Company expects to spend approximately $100 million over the ensuing four to six year period, during which the Company will fulfill the other elements of the settlement, and will capitalize a substantial majority of the costs as property, plant and equipment, representing the costs to construct the charging network and the wiring, which will be productive assets. The Company will expense the costs to operate the assets as incurred. The documented agreement was executed and submitted to FERC on April 27, 2012 for its approval. The settlement agreement was approved by FERC on November 2, 2012. Final settlement payment of $20 million was made on January 16, 2013. Given that there was no challenge to the FERC order approving the settlement in the statutory period, the order became final and non-appealable.
Louisiana Generating, LLC
In 2009, the U.S. DOJ, on behalf of the EPA, and later the Louisiana Department of Environmental Quality, or LDEQ, on behalf of the State of Louisiana, sued Louisiana Generating, LLC, or LaGen, a wholly owned subsidiary of NRG, in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. On March 6, 2013, the court entered a Consent Decree resolving the matter. In addition to imposing a fine of $3.5 million and requiring LaGen to carry out mitigation projects totaling $10.5 million, the Consent Decree requires: (i) specified annual emission caps for NOx and SO2; (ii) installation of selective non-catalytic reduction on Units 1, 2 and 3 by May 1, 2014; (iii) installation of dry sorbent injection on Unit 1 by April 15, 2015 followed by a further reduction in SO2 in March 2025; (iv) conversion of Unit 2 to natural gas; and (v) surrender of any excess allowances associated with the NRG owned portion of the plant. Further discussion of this matter can be found in Note 24, Environmental Matters - South Central Region.
In a related matter, soon after the filing of the above referenced U.S. DOJ lawsuit, LaGen sought insurance coverage from its insurance carrier, Illinois Union Insurance Company, or ILU. ILU denied coverage and refused to provide a defense for LaGen, and thereafter LaGen filed a lawsuit in federal district court in the Middle District of Louisiana (which was consolidated with a prior suit filed by ILU) seeking a declaration that ILU must provide coverage to LaGen for the defense costs incurred in defending the U.S. DOJ lawsuit as well as indemnity costs.  LaGen and ILU both filed motions for summary judgment and on January 30, 2012, the district court issued an order granting LaGen's motion finding that ILU had a duty to defend LaGen. On May 25, 2012, ILU filed a petition with the U.S. Court of Appeals for the Fifth Circuit seeking to appeal the trial court's summary judgment ruling. The Fifth Circuit heard oral argument on March 6, 2013. On May 15, 2013, the Fifth Circuit affirmed the district court's ruling that ILU had a duty to defend LaGen against the U.S. DOJ lawsuit and subsequently denied ILU's petition for rehearing. On October 2, 2013, LaGen filed a motion for summary judgment in the U.S. District Court for the Middle District of Louisiana for recovery of LaGen's fees and costs related to the U.S. DOJ lawsuit, as well as its fees and costs related to the insurance coverage action.
Big Cajun II Alleged Opacity Violations — On September 7, 2012, LaGen received a Consolidated Compliance Order & Notice of Potential Penalty, or CCO&NPP, from the LDEQ.  The CCO&NPP alleges there were opacity exceedance events from the Big Cajun II Power Plant on certain dates during the years 2007-2012.  On October 8, 2012, LaGen filed a Request for Administrative Adjudicatory hearing. LaGen and LDEQ have since reached an agreement to resolve the matter for approximately $47,000. The settlement has been published for public comment, and is subject to approval by the Louisiana Attorney General within 90 days of the notice.
Global Warming
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a suit in the U.S. District Court for the Northern District of California against GenOn and 23 other electric generating and oil and gas companies. The lawsuit sought damages of up to $400 million for the cost of relocating the village allegedly because of global warming caused by the GHG emissions of the defendants. In late 2009, the District Court ordered that the case be dismissed and the plaintiffs appealed. In September 2012, the U.S. Court of Appeals for the Ninth Circuit dismissed plaintiffs' appeal. In October 2012, the plaintiffs petitioned for en banc rehearing of the case, which petition was denied in November 2012. In February 2013, plaintiffs filed a petition for certiorari with the U.S. Supreme Court seeking review of the decision of the U.S. Court of Appeals. In May 2013, the U.S. Supreme Court denied plaintiffs' petition, thereby ending the case.
Actions Pursued by MC Asset Recovery
With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings.  MC Asset Recovery is governed by a manager who is independent of NRG and GenOn.  MC Asset Recovery is a disregarded entity for income tax purposes.
Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to GenOn Energy Holdings' bankruptcy proceedings.  In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants.  In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit.  In March 2012, the Court of Appeals reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants.  If MC Asset Recovery succeeds in obtaining any recoveries from the Commerzbank Defendants, the Commerzbank Defendants have asserted that they will seek to file claims in GenOn Energy Holdings' bankruptcy proceedings for the amount of those recoveries.  GenOn Energy Holdings would vigorously contest the allowance of any such claims. If the Commerzbank Defendants were to receive an allowed claim as a result of a recovery by MC Asset Recovery on its claims against them, GenOn Energy Holdings would retain from the net amount recovered by MC Asset Recovery an amount equal to the dollar amount of the resulting allowed claim.
Pending Natural Gas Litigation
GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of antitrust and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which is handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit. The Ninth Circuit reversed the decision of the U.S. District Court for the District of Nevada. On August 26, 2013, GenOn along with the other defendants in the lawsuit filed a petition for certiorari to the U.S. Supreme Court challenging the Ninth Circuit’s decision. On December 2, 2013, the United States Supreme Court requested the views of the U.S. Solicitor General on the petition for certiorari. In September 2012, the State of Nevada Supreme Court, which is handling the remaining case, affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs in the Nevada case filed a petition for certiorari to the U.S. Supreme Court. In June 2013, the U.S. Supreme Court denied the petition for certiorari, thereby ending one of the five lawsuits. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
New Source Review Matters
The EPA and various states are investigating compliance of electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review.” Since 2000, the EPA has made information requests concerning several of the Company's subsidiaries' plants. The Company continues to correspond with the EPA regarding some of these requests. The EPA agreed to share information relating to its investigations with state environmental agencies. In 2005 and 2006, the Company received an NOV from the EPA alleging that past work at Big Cajun II violated regulations regarding new source review. Further discussion of this matter can be found in Note 24, Environmental Matters - South Central Region. In January 2009, the EPA issued an NOV alleging that past work at the Shawville, Portland and Keystone generating facilities violated regulations regarding new source review. In June 2011, the EPA issued an NOV alleging that past work at the Niles and Avon Lake generating facilities violated regulations regarding new source review. In April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at combustion turbines at three of the Company's Connecticut Jet Power facilities and Middletown facility violated regulations regarding new source review.
In December 2007, the NJDEP sued GenOn in the U.S. District Court for the Eastern District of Pennsylvania, alleging that new source review violations occurred at the Portland generating facility. The suit sought installation of BACT for each pollutant, to enjoin GenOn from operating the generating facility if it is not in compliance with the CAA and civil penalties. The suit also named past owners of the plant as defendants, but the claims against the past owners were dismissed. In March 2009, the Connecticut Department of Energy and Environmental Protection became an intervening party to the suit. In July 2013, the court entered a Consent Decree which generally requires the cessation of coal combustion at Portland Units 1 and 2 and the payment of $1 million to benefit the environment in New Jersey and Connecticut. The entry of the Consent Decree resolved this matter.
Cheswick Class Action Complaint
In April 2012, a putative class action lawsuit was filed against GenOn in the Court of Common Pleas of Allegheny County, Pennsylvania alleging that emissions from the Cheswick generating facility have damaged the property of neighboring residents. The Company disputes these allegations. Plaintiffs have brought nuisance, negligence, trespass and strict liability claims seeking both damages and injunctive relief. Plaintiffs seek to certify a class that consists of people who own property or live within one mile of the Company's plant. In July 2012, the Company removed the lawsuit to the U.S. District Court for the Western District of Pennsylvania. In October 2012, the court granted the Company's motion to dismiss, which Plaintiffs appealed to the U.S. Court of Appeals for the Third Circuit. On August 20, 2013, the Third Circuit reversed the decision of the District Court. On September 3, 2013, the Company filed a petition for rehearing with the Third Circuit which was subsequently denied. In February 2014, the Company filed a petition for a writ of certiorari to the U.S. Supreme Court seeking review and reversal of the Third Circuit Decision. The District Court has stayed further proceedings in the case pending a decision on the petition for writ of certiorari.
Cheswick Monarch Mine NOV
In 2008, the PADEP issued an NOV related to the Monarch mine located near the Cheswick generating facility. This mine has not been mined for many years. The Company uses it for disposal of low-volume wastewater from the Cheswick generating facility and for disposal of leachate collected from ash disposal facilities. The NOV addresses the alleged requirement to maintain a minimum pumping volume from the mine. The PADEP indicated it will seek a civil penalty of approximately $200,000. The Company contests the allegations in the NOV and has not agreed to such penalty. The Company is currently planning capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.
Ormond Beach Alleged Federal Clean Water Act Violations
In October 2012, the Wishtoyo Foundation, a California-based cultural and environmental advocacy organization, through its Ventura Coastkeeper Program, filed suit in the U.S. District Court for the Central District of California regarding alleged violations of the CWA associated with discharges of stormwater from the Ormond Beach generating facility. The Wishtoyo Foundation alleged that elevated concentrations of pollutants in stormwater discharged from the Ormond Beach generating facility were affecting adjacent aquatic resources in violation of (i) the Statewide General Industrial Stormwater permit (a general National Pollution Discharge Elimination System permit issued by the California State Water Resources Control Board that authorizes stormwater discharges from industrial facilities in California) and (ii) the state's Porter-Cologne Water Quality Control Act. The Wishtoyo Foundation further alleged that the Company had not implemented effective stormwater control and treatment measures and that the Company had not complied with the sampling and reporting requirements of the General Industrial Stormwater permit. The Company settled this matter in May 2013 and agreed to make operational changes and pay $79,000 in legal fees, $65,000 for supplemental environmental projects, and $15,000 for monitoring costs.
Maryland Fly Ash Facilities
The Company has three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. Fly ash from the Morgantown and Chalk Point generating facilities is disposed of at Brandywine. Fly ash from the Dickerson generating facility is disposed of at Westland. Fly ash is no longer disposed of at the Faulkner facility. As described below, the MDE had sued NRG MD Ash Management and GenOn Mid-Atlantic regarding Faulkner, Brandywine and Westland. The MDE also had threatened not to renew the water discharge permits for all three facilities.
Faulkner Litigation — In May 2008, the MDE sued GenOn MidAtlantic and NRG MD Ash Management in the Circuit Court for Charles County, Maryland alleging violations of Maryland's water pollution laws at Faulkner. The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland's water quality criteria and without the appropriate NPDES permit. The MDE also alleged that GenOn failed to perform certain sampling and reporting required under an applicable NPDES permit. The MDE complaint requested that the court (i) prohibit continuation of the alleged unpermitted discharges, (ii) require GenOn to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (iii) assess civil penalties. In July 2008, GenOn filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order. In January 2011, the MDE dismissed without prejudice its complaint and informed GenOn that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed a complaint against GenOn Mid-Atlantic and NRG MD Ash Management in the U.S. District Court for the District of Maryland alleging violations at Faulkner of the Clean Water Act and Maryland's Water Pollution Control Law. The MDE contends that (i) certain of GenOn's water discharges are not authorized by the existing permit and (ii) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asked the court to, among other things, (i) enjoin further disposal of coal ash; (ii) enjoin discharges that are not authorized by the existing permit; (iii) require numerous technical studies; (iv) impose civil penalties and (v) award MDE attorneys' fees. The Company disputed these allegations.
Brandywine Litigation — In April 2010, the MDE filed a complaint against GenOn MidAtlantic and NRG MD Ash Management in the U.S. District Court for the District of Maryland asserting violations at Brandywine of the CWA and Maryland's Water Pollution Control Law. The MDE contended that the operation of Brandywine has resulted in discharges of pollutants that violate Maryland's water quality criteria. The complaint requested that the court, among other things, (i) enjoin further disposal of coal combustion waste at Brandywine, (ii) require the existing open disposal cells to be closed and capped within one year, (iii) impose civil penalties, and (iv) award MDE attorneys' fees. In September 2010, four environmental advocacy groups became intervening parties in the proceeding.
Westland Litigation — In January 2011, the MDE informed GenOn that it intended to sue for alleged violations at Westland of Maryland's water pollution laws, which suit was filed in U.S. District Court for the District of Maryland in December 2012.
Permit Renewals — In March 2011, the MDE tentatively decided to deny NRG MD Ash Management's application for renewal of the water discharge permit for Brandywine, which could have resulted in a significant increase in operating expenses for GenOn Mid Atlantic's Chalk Point and Morgantown generating facilities. The MDE also had indicated that it was planning to deny the Company's applications for renewal of the water discharge permits for Faulkner and Westland. Denial of the renewal of the water discharge permit for the latter facility could have resulted in a significant increase in operating expenses for the Dickerson generating facility.
Settlement — In April 2013, NRG MD Ash Management and MDE signed a Consent Decree settling the disputes at each of the three ash facilities. GenOn agreed to pay a civil penalty of $1.9 million for alleged past violations and an additional $0.6 million (for agreed prospective penalties while the settlement is implemented). GenOn agreed to develop a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities, for which $47 million has been reserved, and to remediate the site. At this time, the Company cannot reasonably estimate the upper range of its obligation for remediating the sites because the Company has not: (i) finished assessing each site including identifying the full impacts to both ground and surface water and the impacts to the surrounding habitat; (ii) finalized with the MDE the standards to which it must remediate; and (iii) identified the technologies required, if any, to meet the yet to be determined remediation standards at each site nor the timing of the design and installation of such technologies.
Energy Plus Holdings Purported Class Actions
Energy Plus Holdings was sued in six purported class action lawsuits, two in New York, two in New Jersey, and two in Pennsylvania. On February 28, 2013, Energy Plus Holdings entered into a settlement agreement with plaintiffs to resolve all of the claims in the six pending suits, subject to court approval.  On September 17, 2013, the U.S. District Court for the Southern District of New York entered an order approving the settlement. This settlement became final and nonappealable on October 27, 2013. Energy Plus Holdings continues to cooperate with the Connecticut Office of Attorney General and Office of Consumer Counsel and the State of New York Office of Attorney General to resolve certain issues related to Energy Plus Holdings sales, marketing and business practices.  Energy Plus Holdings and the Connecticut Office of Attorney General and Office of Consumer Counsel have been involved in settlement discussions and their efforts to reach a resolution continue.
Purported Class Actions related to July 22, 2012 Announcement of NRG/GenOn Merger Agreement
NRG was named as a defendant in eight purported class actions in Texas and Delaware related to its announcement of its agreement to acquire all outstanding shares of GenOn. These cases were consolidated into one state court case in each of Delaware and Texas and a federal court case in Texas. The plaintiffs generally alleged breach of fiduciary duties, as well as conspiracy, aiding and abetting breaches of fiduciary duties. Plaintiffs generally sought to: be certified as a class; enjoin the merger; direct the defendants to exercise their fiduciary duties; rescind the acquisition; and be awarded attorneys' fees costs and other relief that the court deems appropriate. Plaintiffs also demanded that there be additional disclosures regarding the merger terms. On October 24, 2012, the parties to the Delaware state court case executed a Memorandum of Understanding to resolve the Delaware purported class action lawsuit. In March 2013, the parties finalized the settlement of the Delaware action. On June 3, 2013, the court approved the Delaware class action settlement thereby ending the Delaware lawsuit. The remaining Texas state and federal court cases were dismissed in July 2013 and August 2013, respectively, thereby ending these matters.
Maryland Department of the Environment v. GenOn Chalk Point and GenOn Mid-Atlantic
On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper (together, the Citizens Group) sent NRG a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System permits by discharging nitrogen and phosphorous in excess of the limits in each permit. On March 21, 2013, the MDE sent the Company a similar letter with respect to the Chalk Point and Dickerson facilities, threatening to sue within 60 days if the Company did not bring itself into compliance. On June 11, 2013, the Maryland Attorney General on behalf of the MDE filed a complaint in the U.S. District Court for the District of Maryland alleging violations of the Clean Water Act and Maryland environmental laws related to water. The lawsuit seeks injunctive relief and civil penalties in excess of $100,000.
Huntley Power LLC Subpoena
Huntley Power LLC was served with a subpoena on May 13, 2013 from the U.S. Department of Justice requesting information regarding the plant's use and handling of diesel fuel. The Company cooperated with the U.S Department of Justice inquiry into the issues related to the use and handling of diesel fuel. The U.S. Department of Justice has advised that it is not pursuing information related to this subpoena and has closed its file, thereby ending the matter.
Texas Franchise Audit
During the second quarter of 2013, the Company settled the Texas Franchise tax dispute with the state relating to years 2001 through 2007. Prior to the GenOn acquisition, the State of Texas issued franchise tax assessments against GenOn as a result of its audit indicating an underpayment of franchise tax of $72 million (including interest and penalties through June 30, 2013 of $29 million). These assessments relate primarily to a claim by Texas that would change the sourcing of intercompany receipts thereby increasing the amount of tax due. GenOn disagreed with most of the State's assessment and its determination and had accordingly accrued a portion of the liability but had protested the entire assessment.  In June 2013, the Company settled the matter with the State by agreeing to pay $11 million on issues arising from the audit, and reversed the remainder of the accrual. The reversal was recorded as a measurement period adjustment to the amounts recognized on the acquisition date.

Regulatory_Matters_Notes

Regulatory Matters (Notes)	12 Months Ended
	Dec. 31, 2013
Regulatory Matters Disclosure [Abstract]	'
Regulatory Matters	'
	Regulatory Matters
	NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.
	In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
	East Region
	Reliability Must Run Agreements for Elrama and Niles — In May 2012, GenOn filed with FERC an RMR rate schedule governing operation of unit 4 of the Elrama generating facility and unit 1 of the Niles generating facility.  PJM determined that each of these units was needed past its planned deactivation date of June 1, 2012 to maintain transmission system reliability on the PJM system pending the completion of transmission upgrades.  The RMR rate schedule sets forth the terms, conditions and cost-based rates under which GenOn operated the units for reliability purposes through September 30, 2012, the date PJM indicated the units would no longer be needed for reliability.  In July 2012, FERC accepted GenOn's RMR rate schedule subject to hearing and settlement procedures.  In the settlement discussions ordered by FERC, or in any subsequent hearing, the Company's RMR rate schedule may be modified from that which was filed.  The rates GenOn charged are subject to refund pending a ruling or settlement. The Company filed a settlement of all outstanding issues in May 2013, which several parties are contesting. The matter is pending before FERC.
	Montgomery County Station Power Tax — On December 20, 2013, the Company received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the last three years.  The letter seeks payment in the amount of $14.6 million, which includes tax, interest and penalty.  The Company is disputing the applicability of the tax and GenOn Mid-Atlantic, LLC filed suit against the County in Maryland Tax Court and the Circuit Court for Montgomery County on January 21, 2014. The parties jointly filed on February 25, 2014, to stay the Circuit Court proceeding pending resolution of the Tax Court proceeding.  The Tax Court proceeding is still pending.
	Retail
	MISO SECA — Green Mountain Energy previously provided competitive retail energy supply in the MISO region during the relevant period of January 1, 2002, to December 31, 2005.  By order dated November 18, 2004, FERC eliminated certain regional through-and-out transmission rates charged by transmission owners in MISO and PJM. In order to temporarily compensate the transmission owners for lost revenues, FERC ordered MISO, PJM and their respective transmission owners to revamp the way that ISOs manage certain cross-system congestion costs, known as Seams Elimination Charge/Cost Adjustments/Assignments, or SECA, charges effective December 1, 2004, through March 31, 2006.  The tariff amendments filed by MISO and the MISO transmission owners allocated certain SECA charges to various zones and sub-zones within MISO, including a sub-zone called the Green Mountain Energy Company Sub-zone.  During several years of extensive litigation before FERC, several transmission owners sought to recover SECA charges from Green Mountain Energy. Green Mountain Energy denied responsibility for any SECA charges and did not pay any asserted SECA charges.
	On May 21, 2010, FERC issued two orders, including its Order on Initial Decision, in which FERC determined that approximately $22 million plus interest of SECA charges were owed not by Green Mountain Energy but rather by BP Energy - one of Green Mountain Energy's suppliers during the period at issue.  On August 19, 2010, the transmission owners and MISO made compliance filings in accordance with FERC's Orders allocating SECA charges to a BP Energy Sub-zone, and making no allocation to a Green Mountain Energy sub-zone.  FERC has not yet ruled on those compliance filings.
	On September 30, 2011, FERC issued orders denying all requests for rehearing and again determined that SECA charges were not owed by Green Mountain Energy.  Numerous parties, including BP Energy, sought judicial review of FERC's orders, and Green Mountain Energy was granted intervenor status in the consolidated appeals. Most appellants subsequently settled with the transmission owners and withdrew their appeals, including BP Energy, which agreed to pay approximately $24 million to the three transmission owners signing the agreement, with another $1 million offered to the remaining PJM transmission owners, should they choose to join the settlement; all chose to do so. FERC approved the settlement, and BP Energy moved to dismiss its appeals; its motions to dismiss were granted by the Court.
	West Region
	California Station Power — On December 18, 2012, in Calpine Corporation v. FERC, the U.S. Court of Appeals for the D.C. Circuit upheld a decision by FERC disclaiming jurisdiction over how the states impose retail station power charges. The CPUC may now establish retail charges for future station power consumption. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, the court's ruling arguably requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO's station power program (February 1, 2009, for the Company's Encina and El Segundo facilities; March 1, 2009, for the Company's Long Beach facility).
	On November 18, 2011, Southern California Edison Company filed with the CPUC, seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. On August 13, 2012, the CPUC Energy Division issued a draft resolution in which it rejected the Company's arguments and approved Southern California Edison's proposed station power charges, including retroactive implementation, but proposing a credit to generators for some portion of their retail station power bill. However, the CPUC withdrew the draft resolution from the calendar and consideration of the measure has not yet been rescheduled. The Company believes it has established an appropriate reserve.

Environmental_Matters_Notes

Environmental Matters (Notes)	12 Months Ended
	Dec. 31, 2013
Environmental Matters Disclosure [Abstract]	'
Environmental Matters	'
	Environmental Matters
	NRG is subject to a wide range of environmental regulations in the development, ownership, construction and operation of projects in the United States and Australia. These laws and regulations generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental regulations have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is likely to face new requirements to address various emissions, including greenhouse gases, as well as combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws and regulations are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations.
	The EPA released CSAPR on July 7, 2011, which was scheduled to replace CAIR on January 1, 2012. On August 21, 2012, the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating CSAPR and keeping CAIR in place until the EPA can replace it. The EPA petitioned the U.S. Supreme Court seeking review of this decision, which petition was granted. The Supreme Court heard oral argument in the case on December 10, 2013. The Court of Appeals decision was beneficial to the Company as it eliminated an SO2 allowance reduction which was to have occurred before the MATS compliance date. While NRG is unable to predict the final outcome of the ongoing litigation, the Company's investment in pollution controls and cleaner technologies coupled with planned strategic plant retirements leaves the fleet well positioned for compliance.
	Under CSAPR, use of discounted Acid Rain SO2 and CAIR NOx allowances would have been discontinued and replaced with completely distinct allowance programs. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. Consequently, in the third quarter 2011, the Company recorded an impairment charge of $160 million 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.
	In January 2014, EPA re-proposed the NSPS for CO2 emissions from new fossil-fuel-fired electric generating units that had been previously proposed in April 2012. The re-proposed standards are 1,000 pounds of CO2 per MWh for large gas units and 1,100 pounds of CO2 per MWh for coal units and small gas units. Proposed standards are in effect until a final rule is published or another rule is re-proposed. In 2014, EPA intends to propose another rule that would require states to develop CO2 standards that would apply to existing fossil-fueled generating facilities.
	Environmental Capital Expenditures
	Based on current (and in some cases proposed) rules, technology and preliminary plans based on some proposed rules, NRG estimates that environmental capital expenditures from 2014 through 2018 required to comply with environmental laws will be approximately $332 million, which includes $120 million for GenOn. These costs are primarily associated with (i) controls to satisfy MATS and the recent NSR settlement at Big Cajun II; (ii) controls to satisfy MATS at W.A. Parish, Limestone and Conemaugh; and (iii) NOx controls for Sayreville and Gilbert. NRG continues to explore cost-effective compliance alternatives to further reduce costs.
	NRG's contracts with its rural electric cooperative customers in the South Central region allow for recovery of a portion of the region's environmental capital costs incurred as the result of complying with any change in environmental law. Cost recoveries begin once the environmental equipment becomes operational and include a return on capital. 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.
	East Region
	The EPA and various states are investigating compliance of electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review,” or NSR. In January 2009, GenOn received an NOV from the EPA alleging that past work at Keystone, Portland and Shawville generating facilities violated regulations regarding NSR. In June 2011, GenOn received an NOV from the EPA alleging that past work at Avon Lake and Niles generating stations violated NSR. In December 2007, the NJDEP filed suit alleging that NSR violations occurred at the Portland generating station, which suit was resolved pursuant to a July 2013 Consent Decree. The Shawville and Portland generating units that are the subject of the NOVs are scheduled for retirement soon. The Niles coal generating unit, also subject to the NOV, was retired in 2012. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines at the Torrington Terminal, Franklin, Branford and Middletown violated regulations regarding NSR.
	In 2008, the PADEP issued an NOV related to the inactive Monarch mine where low-volume wastewater from the Cheswick Generating Station and ash leachate was historically disposed. Resolution of the NOV could result in operational requirements such as pumping a minimum volume of water from the mine and a penalty of approximately $200,000.
	In January 2006, NRG's Indian River Operations, Inc. was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. The DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. The cost of completing the work required by the approved remediation plan is consistent with amounts previously budgeted. On May 29, 2008, DNREC requested that NRG's Indian River Operations, Inc. participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment process.
	The MDE sued GenOn for alleged violations of water pollution laws at three fly ash disposal sites in Maryland: Faulkner (2008/2011), Brandywine (2010) and Westland (2012). On April 30, 2013, the court approved the consent decree resolving these issues. GenOn has discontinued use of the Faulkner disposal site and opened a new, state of the art carbon burnout facility at its Morgantown plant that allows greater beneficial reuse (as a cement substitute).
	In addition, the MDE has announced that it intends to promulgate more stringent regulations regarding NOx emissions, which could negatively affect certain of the Company's coal facilities located in Maryland.
	In 2013, each of the RGGI member states finalized a rule that collectively reduced the CO2 emissions cap from 165 million tons to 91 million tons in 2014 with a 2.5% reduction each year from 2015 to 2020. The Company expects earnings at its plants in Massachusetts, New York, and particularly those in Maryland, to be negatively affected. The extent to which the Company would be negatively affected depends on the price of the CO2 emissions allowances, which in turn will be significantly influenced by future natural gas prices, power prices, generation resource mix, dispatch order, and any nuclear plant retirements.
	For further discussion of these matters, refer to Note 22, Commitments and Contingencies.
	South Central Region
	In 2009, the U.S. DOJ, on behalf of the EPA, and later the Louisiana Department of Environmental Quality on behalf of the state of Louisiana, sued LaGen in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. On March 6, 2013, the court entered a Consent Decree resolving the matter. In addition to a fine of $3.5 million and mitigation projects totaling $10.5 million the Consent Decree includes: (i) annual emission caps for NOx and SO2; (ii) installation of selective non-catalytic reduction on Units 1, 2 and 3 by May 1, 2014; (iii) installation of dry sorbent injection on Unit 1 by April 15, 2015 followed by a further reduction in SO2 in March 2025; (iv) conversion of Unit 2 to natural gas; and (v) surrender of any excess allowances associated with the NRG owned portion of the plant. For further discussion of this matter, refer to Note 22, Commitments and Contingencies.

Cash_Flow_Information_Notes

Cash Flow Information (Notes)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Cash Flow Information	'
	Cash Flow Information
	Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
		Year Ended December 31,
		2013			2012			2011
		(In millions)
	Interest paid, net of amount capitalized	$	836		$	579		$	642
	Income taxes (refunded)/paid (a)	(60		)	17			26
	Non-cash investing and financing activities:
	Additions to fixed assets for accrued capital expenditures	405			563			292
	Decrease to fixed assets for accrued grants and related tax impact	(681		)	(87		)	(32		)
	Decrease to notes receivable for equity conversion	—			—			63
	Issuance of shares for GenOn acquisition	—			(2,188		)	—
	(a) In 2013, the net income taxes refunded are net of $28 million income taxes paid and $87 million income tax refunds. No tax refunds were received in 2012. In 2011, income taxes paid are net of $8 million of income tax refunds received.

Guarantees_Notes

Guarantees (Notes)	12 Months Ended
	Dec. 31, 2013
Guarantees [Abstract]	'
Guarantees	'
	Guarantees
	NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is obligated with respect to customer deposits associated with the Retail Business. NRG has also assumed guarantees for some non-qualified benefits of existing retirees resulting from the acquisition of GenOn. In some cases, NRG's maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.
	In accordance with ASC 460, Guarantees, or ASC 460, NRG has estimated that the current fair value for issuing these guarantees was $5.4 million as of December 31, 2013, and the liability in this amount is included in the Company's non-current liabilities.
	The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity:
		By Remaining Maturity at December 31,
		2013
	Guarantees	Under		1-3 Years		3-5 Years		Over		Total		2012
		1 Year						5 Years				Total
		(In millions)
	Letters of credit and surety bonds	$	1,654	$	47	$	—	$	—	$	1,701	$	1,594
	Asset sales guarantee obligations	—		—		275		—		275		275
	Commercial sales arrangements	81		112		23		1,338		1,554		1,579
	Other guarantees	78		4		—		469		551		356
	Total guarantees	$	1,813	$	163	$	298	$	1,807	$	4,081	$	3,804
	Letters of credit and surety bonds — As of December 31, 2013, NRG and its consolidated subsidiaries were contingently obligated for a total of $1.8 billion under letters of credit and surety bonds. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements and in support of equity contribution requirements for solar projects in construction, as well as for financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms.
	The material indemnities, within the scope of ASC 460, are as follows:
	Asset purchases and divestitures — The purchase and sale agreements which govern NRG's asset or share investments and divestitures customarily contain guarantees and indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.
	Commercial sales arrangements — In connection with the purchase and sale of fuel, emission allowances and power generation products to and from third parties with respect to the operation of some of NRG's generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments.
	Other guarantees — NRG has issued guarantees of obligations that its subsidiaries may incur as a provision for environmental site remediation, payment of debt obligations, rail car leases, performance under purchase, EPC and operating and maintenance agreements. The Company does not believe that it will be required to perform under these guarantees.
	Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any material payments under these indemnity provisions.
	Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be able to estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.

Jointly_Owned_Plants_Notes

Jointly Owned Plants (Notes)	12 Months Ended
	Dec. 31, 2013
Jointly Owned Plants Disclosure [Abstract]	'
Jointly Owned Plants	'
	Jointly Owned Plants
	Certain NRG subsidiaries own undivided interests in jointly-owned plants, as described below. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries' share of operating costs and direct expenses and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company's consolidated financial statements.
	The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities:
	As of December 31, 2013	Ownership		Property, Plant &		Accumulated			Construction in
		Interest		Equipment		Depreciation			Progress
		(In millions unless otherwise stated)
	South Texas Project Units 1 and 2, Bay City, TX	44	%	$	2,679	$	(1,293	)	$	19
	Big Cajun II Unit 3, New Roads, LA	58	%	178		(95		)	18
	Cedar Bayou Unit 4, Baytown, TX	50	%	215		(49		)	—
	Keystone, Shelocta, PA	3.7	%	92		(35		)	1
	Conemaugh, New Florence, PA	3.72	%	82		(38		)	14

Unaudited_Quarterly_Financial_

Unaudited Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Unaudited Quarterly Financial Data	'
	Unaudited Quarterly Financial Data
	Refer to Note 3, Business Acquisitions and Dispositions, and Note 10, Asset Impairments, for a description of the effect of unusual or infrequently occurring events during the quarterly periods. Summarized unaudited quarterly financial data is as follows:
		Quarter Ended
		2013
		December 31			September 30			June 30		March 31
		(In millions, except per share data)
	Operating revenues	$	2,795		$	3,490		$	2,930	$	2,081
	Operating (loss)/income	(205		)	527			287		(266		)
	Net (loss)/income	(283		)	$	135		130		(334		)
	Net (loss)/income attributable to NRG Energy, Inc.	$	(290	)	$	116		$	122	$	(334	)
	Weighted average number of common shares outstanding — basic	323			323			323		323
	Net (loss)/income per weighted average common share — basic	$	(0.90	)	$	0.36		$	0.38	$	(1.03	)
	Weighted average number of common shares outstanding — diluted	323			327			327		323
	Net (loss)/income per weighted average common share — diluted	$	(0.90	)	$	0.35		$	0.37	$	(1.03	)
		Quarter Ended
		2012
		December 31			September 30			June 30		March 31
		(In millions, except per share data)
	Operating revenues	$	2,063		$	2,331		$	2,166	$	1,862
	Operating income/(loss)	37			86			397		(170		)
	Net income/(loss)	254			8			259		(206		)
	Net income/(loss) attributable to NRG Energy, Inc.	$	252		$	(1	)	$	251	$	(207	)
	Weighted average number of common shares outstanding — basic	247			228			228		228
	Net income/(loss) per weighted average common share — basic	$	1.02		$	(0.01	)	$	1.09	$	(0.92	)
	Weighted average number of common shares outstanding — diluted	249			228			229		228
	Net income/(loss) per weighted average common share — diluted	$	1.01		$	(0.01	)	$	1.08	$	(0.92	)

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information (Notes)	12 Months Ended
	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Condensed Consolidating Financial Information	'
	Condensed Consolidating Financial Information
	As of December 31, 2013, the Company had outstanding $5.7 billion of Senior Notes due 2018 - 2023, as shown in Note 12, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries.
	Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2013:
	Ace Energy, Inc.	Middletown Power LLC	NRG Oswego Harbor Power Operations Inc.
	Allied Warranty LLC	Montville Power LLC	NRG PacGen Inc.
	Allied Home Warranty GP LLC	NEO Corporation	NRG Power Marketing LLC
	Arthur Kill Power LLC	NEO Freehold-Gen LLC	NRG Reliability Solutions LLC
	Astoria Gas Turbine Power LLC	NEO Power Services Inc.	NRG Renter's Protection LLC
	BidURenergy, Inc.	New Genco GP, LLC	NRG Retail LLC
	Cabrillo Power I LLC	Norwalk Power LLC	NRG Retail Northeast LLC
	Cabrillo Power II LLC	NRG Affiliate Services Inc.	NRG Rockford Acquisition LLC
	Carbon Management Solutions LLC	NRG Artesian Energy LLC	NRG Saguaro Operations Inc.
	Clean Edge Energy LLC	NRG Arthur Kill Operations Inc.	NRG Security LLC
	Conemaugh Power LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Services Corporation
	Connecticut Jet Power LLC	NRG Bayou Cove LLC	NRG SimplySmart Solutions LLC
	Cottonwood Development LLC	NRG Cabrillo Power Operations Inc.	NRG South Central Affiliate Services Inc.
	Cottonwood Energy Company LP	NRG California Peaker Operations LLC	NRG South Central Generating LLC
	Cottonwood Generating Partners I LLC	NRG Cedar Bayou Development Company, LLC	NRG South Central Operations Inc.
	Cottonwood Generating Partners II LLC	NRG Connecticut Affiliate Services Inc.	NRG South Texas LP
	Cottonwood Generating Partners III LLC	NRG Construction LLC	NRG Texas C&I Supply LLC
	Cottonwood Technology Partners LP	NRG Curtailment Solutions LLC	NRG Texas Gregory LLC
	Devon Power LLC	NRG Development Company Inc.	NRG Texas Holding Inc.
	Dunkirk Power LLC	NRG Devon Operations Inc.	NRG Texas LLC
	Eastern Sierra Energy Company LLC	NRG Dispatch Services LLC	NRG Texas Power LLC
	El Segundo Power, LLC	NRG Dunkirk Operations Inc.	NRG Unemployment Protection LLC
	El Segundo Power II LLC	NRG El Segundo Operations Inc.	NRG Warranty Services LLC
	Elbow Creek Wind Project LLC	NRG Energy Labor Services LLC	NRG West Coast LLC
	Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Western Affiliate Services Inc.
	Energy Curtailment Specialists, Inc.	NRG Energy Services International Inc.	O'Brien Cogeneration, Inc. II
	Energy Plus Holdings LLC	NRG Energy Services LLC	ONSITE Energy, Inc.
	Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	Oswego Harbor Power LLC
	Energy Protection Insurance Company	NRG Home & Business Solutions LLC	RE Retail Receivables, LLC
	Everything Energy LLC	NRG Home Solutions LLC	Reliant Energy Northeast LLC
	GCP Funding Company, LLC	NRG Home Solutions Product LLC	Reliant Energy Power Supply, LLC
	Green Mountain Energy Company	NRG Homer City Services LLC	Reliant Energy Retail Holdings, LLC
	Green Mountain Energy Company	NRG Huntley Operations Inc.	Reliant Energy Retail Services, LLC
	(NY Com) LLC	NRG Identity Protect LLC	RERH Holdings LLC
	Green Mountain Energy Company	NRG Ilion Limited Partnership	Saguaro Power LLC
	(NY Res) LLC	NRG Ilion LP LLC	Somerset Operations Inc.
	Gregory Partners, LLC	NRG International LLC	Somerset Power LLC
	Gregory Power Partners LLC	NRG Maintenance Services LLC	Texas Genco Financing Corp.
	Huntley Power LLC	NRG Mextrans Inc.	Texas Genco GP, LLC
	Independence Energy Alliance LLC	NRG MidAtlantic Affiliate Services Inc.	Texas Genco Holdings, Inc.
	Independence Energy Group LLC	NRG Middletown Operations Inc.	Texas Genco LP, LLC
	Independence Energy Natural Gas LLC	NRG Montville Operations Inc.	Texas Genco Operating Services, LLC
	Indian River Operations Inc.	NRG New Jersey Energy Sales LLC	Texas Genco Services, LP
	Indian River Power LLC	NRG New Roads Holdings LLC	US Retailers LLC
	Keystone Power LLC	NRG North Central Operations Inc.	Vienna Operations Inc.
	Langford Wind Power, LLC	NRG Northeast Affiliate Services Inc.	Vienna Power LLC
	Lone Star A/C & Appliance Repairs, LLC	NRG Norwalk Harbor Operations Inc.	WCP (Generation) Holdings LLC
	Louisiana Generating LLC	NRG Operating Services, Inc.	West Coast Power LLC
	Meriden Gas Turbines LLC
	The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company's Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries.
	The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
	In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.
	In addition, the condensed parent company financial statements are provided in accordance with Rule 12-04, Schedule I of Regulation S-X, as the restricted net assets of NRG Energy, Inc.’s subsidiaries exceed 25 percent of the consolidated net assets of NRG Energy, Inc. These statements should be read in conjunction with the consolidated statements and notes thereto of NRG Energy, Inc. For a discussion of NRG Energy, Inc.'s long-term debt, see Note 12, Debt and Capital Leases to the consolidated financial statements. For a discussion of NRG Energy, Inc.'s contingencies, see Note 22, Commitments and Contingencies to the consolidated financial statements. For a discussion of NRG Energy, Inc.'s guarantees, see Note 26, Guarantees to the consolidated financial statements.
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	For the Year Ended December 31, 2013
		Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
		Subsidiaries			Subsidiaries			(Note Issuer)						Balance
		(In millions)
	Operating Revenues
Total operating revenues	$	8,223		$	3,211		$	—		$	(139	)	$	11,295
Operating Costs and Expenses
Cost of operations	6,150			2,104			—			(133		)	8,121
Depreciation and amortization	837			407			12						1,256
Impairment losses	459			—			—			—			459
Selling, general and administrative	446			230			234			(6		)	904
Acquisition-related transaction and integration costs	—			70			58			—			128
Development activity expenses	—			34			50			—			84
Total operating costs and expenses	7,892			2,845			354			(139		)	10,952
Operating Income/(Loss)	331			366			(354		)	—			343
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	(67		)	(14		)	221			(140		)	—
Equity in earnings/(losses) of unconsolidated affiliates	(11		)	22			—			(4		)	7
Impairment charge on investment	—			(99		)				—			(99		)
Other income, net	6			11			(2		)	(2		)	13
Loss on debt extinguishment				(12		)	(38		)	—			(50		)
Interest expense	(24		)	(318		)	(506		)	—			(848		)
Total other income/(expense)	(96		)	(410		)	(325		)	(146		)	(977		)
Income/(Loss) Before Income Taxes	235			(44		)	(679		)	(146		)	(634		)
Income tax expense/(benefit)	114			(89		)	(307		)	—			(282		)
Net Income	121			45			(372		)	(146		)	(352		)
Less: Net income attributable to noncontrolling interest	—			27			13			(6		)	34
Net Income attributable to NRG Energy, Inc	$	121		$	18		$	(385	)	$	(140	)	$	(386	)
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Year Ended December 31, 2013
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc.			Eliminations(a)			Consolidated Balance
							(Note Issuer)
	(In millions)
Net Income	$	121		$	45		$	(372	)	$	(146	)	$	(352	)
Other comprehensive (loss)/income, net of tax
Unrealized loss on derivatives, net	(71		)	50			120			(91		)	8
Foreign currency translation adjustments, net	—			(20		)	(4		)	—			(24		)
Available-for-sale securities, net	—			—			3			—			3
Defined benefit plan, net	75			63			30			—			168
Other comprehensive loss	4			93			149			(91		)	155
Comprehensive income	125			138			(223		)	(237		)	(197		)
Less: Comprehensive income attributable to noncontrolling interest	—			27			13			(6		)	34
Comprehensive income attributable to NRG Energy, Inc.	125			111			(236		)	(231		)	(231		)
Dividends for preferred shares	—			—			9			—			9
Comprehensive income available for common stockholders	$	125		$	111		$	(245	)	$	(231	)	$	(240	)
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2013
	Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated Balance
	Subsidiaries			Subsidiaries
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	56		$	870		$	1,328		$	—		$	2,254
Funds deposited by counterparties	7			56			—			—			63
Restricted cash	12			252			4			—			268
Accounts receivable - trade, net	965			249			—			—			1,214
Inventory	436			462			—			—			898
Derivative instruments	866			470			—			(8		)	1,328
Deferred income taxes	—			41			217			—			258
Cash collateral paid in support of energy risk management activities	214			62			—			—			276
Renewable energy grant receivable	—			539			—			—			539
Prepayments and other current assets	4,778			379			(3,802		)	(857		)	498
Total current assets	7,334			3,380			(2,253		)	(865		)	7,596
Net Property, Plant and Equipment	9,116			10,604			153			(22		)	19,851
Other Assets
Investment in subsidiaries	32			422			18,266			(18,720		)	—
Equity investments in affiliates	(30		)	583						(100		)	453
Notes receivable, less current portion	—			62			105			(94		)	73
Goodwill	1,973			12			—			—			1,985
Intangible assets, net	925			232			4			(21		)	1,140
Nuclear decommissioning trust fund	551						—			—			551
Deferred income taxes	—			681			521			—			1,202
Derivative instruments	110			202			—			(1		)	311
Other non-current assets	76			281			383			—			740
Total other assets	3,637			2,475			19,279			(18,936		)	6,455
Total Assets	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	1,029		$	20		$	—		$	1,050
Accounts payable	652			352			34			—			1,038
Accounts payable - affiliate	1,350			760			(1,253		)	(857		)	—
Derivative instruments	859			204			—			(8		)	1,055
Deferred income taxes	—			—			—			—			—
Cash collateral received in support of energy risk management activities	6			57			—			—			63
Accrued expenses and other current liabilities	297			410			291			—			998
Total current liabilities	3,165			2,812			(908		)	(865		)	4,204
Other Liabilities
Long-term debt and capital leases	317			7,837			7,707			(94		)	15,767
Nuclear decommissioning reserve	294			—			—			—			294
Nuclear decommissioning trust liability	324			—			—			—			324
Postretirement and other benefit obligations	218			194			94			—			506
Deferred income taxes	1,024			(1,002		)	—			—			22
Derivative instruments	147			49			—			(1		)	195
Out-of-market contracts	127			1,050			—			—			1,177
Other non-current liabilities	194			421			80			—			695
Total non-current liabilities	2,645			8,549			7,881			(95		)	18,980
Total liabilities	5,810			11,361			6,973			(960		)	23,184
3.625% Preferred Stock							249						249
Stockholders' Equity	14,277			5,098			9,957			(18,863		)	10,469
Total Liabilities and Stockholders' Equity	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2013
	Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
	Subsidiaries			Subsidiaries									Balance
	(In millions)
Net Cash Provided/(Used) by Operating Activities	2,318			(217		)	(2,546		)	1,715			1,270
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(1,722		)	7			1,715			—			—
Acquisition of business, net of cash acquired				(179		)	(315		)	—			(494		)
Capital expenditures	(528		)	(1,413		)	(46		)	—			(1,987		)
Increase in restricted cash, net	(1		)	(22		)	1			—			(22		)
Decrease in restricted cash - U.S. DOE projects				(31		)	5			—			(26		)
Increase in notes receivable	2			(7		)	(6		)	—			(11		)
Proceeds from renewable energy grants				55			—			—			55
Purchases of emission allowances, net of proceeds	5			—			—			—			5
Investments in nuclear decommissioning trust fund securities	(514		)	—			—			—			(514		)
Proceeds from sales of nuclear decommissioning trust fund securities	488			—			—			—			488
Proceeds/(purchases) from sale of assets, net	13			—			—			—			13
Other	(4		)	(11		)	(20		)	—			(35		)
Net Cash Used by Investing Activities	(2,261		)	(1,601		)	1,334			—			(2,528		)
Cash Flows from Financing Activities
Proceeds/(payments) from intercompany loans	—			—			1,715			(1,715		)	—
Payment of dividends to preferred stockholders							(154		)	—			(154		)
Payments of intercompany dividends	—			—			—			—			—
Payment for treasury stock	—			—			(25		)	—			(25		)
Payments for settlement of acquired derivatives that include financing elements	(79		)	346			—			—			267
Proceeds from issuance of long-term debt	—			1,292			485			—			1,777
Sale proceeds and other contributions from noncontrolling interests in subsidiaries	—			531			—			—			531
Proceeds from issuance of common stock	—			—			16			—			16
Payment of debt issuance and hedging costs	—			(21		)	(29		)	—			(50		)
Payments for short and long-term debt	—			(716		)	(219		)	—			(935		)
Net Cash (Used)/Provided by Financing Activities	(79		)	1,432			1,789			(1,715		)	1,427
Effect of exchange rate changes on cash and cash equivalents	—			(2		)	—			—			(2		)
Net Increase/(decrease) in Cash and Cash Equivalents	(22		)	(388		)	577			—			167
Cash and Cash Equivalents at Beginning of Period	78			1,258			751			—			2,087
Cash and Cash Equivalents at End of Period	$	56		$	870		$	1,328		$	—		$	2,254
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2012
	Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
	Subsidiaries			Subsidiaries			(Note Issuer)						Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,998		$	509		$	—		$	(85	)	$	8,422
Operating Costs and Expenses
Cost of operations	5,916			300			—			(76		)	6,140
Depreciation and amortization	860			79			11			—			950
Selling, general and administrative	466			45			307			(11		)	807
Acquisition-related transactions and integration costs	—			53			54			—			107
Development activity expense	—			32			36			—			68
Total operating costs and expenses	7,242			509			408			(87		)	8,072
Operating Income/(Loss)	756			—			(408		)	2			350
Other (Expense)/Income
Equity in earnings/(losses) of consolidated subsidiaries	30			(15		)	620			(635		)	—
Equity in earnings/(losses) of unconsolidated affiliates	8			31			(2		)	—			37
Bargain purchase gain related to GenOn acquisition	—			—			296			—			296
Impairment charge on investment	(2		)	—			—			—			(2		)
Other income, net	6			6			9			(2		)	19
Loss on debt extinguishment	—			—			(51		)	—			(51		)
Interest expense	(26		)	(90		)	(545		)	—			(661		)
Total other income/(expense)	16			(68		)	327			(637		)	(362		)
Income/(Loss) Before Income Taxes	772			(68		)	(81		)	(635		)	(12		)
Income tax expense/(benefit)	237			(188		)	(376		)	—			(327		)
Net Income	$	535		$	120		$	295		$	(635	)	$	315
Less: Net income attributable to noncontrolling interest	—			20			—			—			20
Net Income attributable to NRG Energy, Inc	$	535		$	100		$	295		$	(635	)	$	295
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Year Ended December 31, 2012
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc.			Eliminations(a)			Consolidated Balance
							(Note Issuer)
	(In millions)
Net Income	$	535		$	120		$	295		$	(635	)	$	315
Other comprehensive income/(loss), net of tax
Unrealized loss on derivatives, net	(160		)	(30		)	(214		)	241			(163		)
Foreign currency translation adjustments, net	—			(2		)	1			—			(1		)
Reclassification adjustment for translation loss realized upon sale of Schkopau, net	—			(11		)	—			—			(11		)
Available-for-sale securities, net	—			—			3			—			3
Defined benefit plan, net	(38		)	—			(14		)	—			(52		)
Other comprehensive loss	(198		)	(43		)	(224		)	241			(224		)
Comprehensive income	337			77			71			(394		)	91
Less: Comprehensive income attributable to noncontrolling interest	—			20			—			—			20
Comprehensive income attributable to NRG Energy, Inc.	337			57			71			(394		)	71
Dividends for preferred shares	—			—			9			—			9
Comprehensive income available for common stockholders	$	337		$	57		$	62		$	(394	)	$	62
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2012
	Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
	Subsidiaries			Subsidiaries									Balance
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	78		$	1,258		$	751		$	—		$	2,087
Funds deposited by counterparties	131			140			—			—			271
Restricted cash	11			196			10			—			217
Accounts receivable - trade, net	807			254			—			—			1,061
Inventory	472			431			—			—			903
Derivative instruments	2,058			604			—			(18		)	2,644
Deferred income taxes	(153		)	10			199			—			56
Cash collateral paid in support of energy risk management activities	81			148			—			—			229
Renewable energy grant receivable	—			58			—			—			58
Prepayments and other current assets	2,966			(12		)	(2,518		)	10			446
Total current assets	6,451			3,087			(1,558		)	(8		)	7,972
Net Property, Plant and Equipment	9,905			10,147			121			(20		)	20,153
Other Assets
Investment in subsidiaries	244			(102		)	17,565			(17,707		)	—
Equity investments in affiliates	33			633			10			—			676
Notes receivable, less current portion	3			74			531			(529		)	79
Goodwill	1,944			12			—			—			1,956
Intangible assets, net	1,042			187			33			(52		)	1,210
Nuclear decommissioning trust fund	473			—			—			—			473
Deferred income taxes	(915		)	1,886			232			—			1,203
Derivative instruments	149			515			—			(2		)	662
Other non-current assets	85			304			210			—			599
Total other assets	3,058			3,509			18,581			(18,290		)	6,858
Total Assets	$	19,414		$	16,743		$	17,144		$	(18,318	)	$	34,983
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	137		$	15		$	(6	)	$	147
Accounts payable	541			585			46			—			1,172
Accounts payable - affiliate	(55		)	1,421			(1,366		)	—			—
Derivative instruments	1,726			271			2			(18		)	1,981
Cash collateral received in support of energy risk management activities	131			140			—			—			271
Accrued expenses and other current liabilities	354			502			243			—			1,099
Total current liabilities	2,698			3,056			(1,060		)	(24		)	4,670
Other Liabilities
Long-term debt and capital leases	310			8,459			7,496			(529		)	15,736
Nuclear decommissioning reserve	354			—			—			—			354
Nuclear decommissioning trust liability	273			—			—			—			273
Postretirement and other benefit obligations	431			326			46			—			803
Deferred income taxes	—			—			55			—			55
Derivative instruments	312			190			—			(2		)	500
Out-of-market commodity contracts	180			1,129			—			(31		)	1,278
Other non-current liabilities	187			520			89			—			796
Total non-current liabilities	2,047			10,624			7,686			(562		)	19,795
Total liabilities	4,745			13,680			6,626			(586		)	24,465
3.625% Preferred Stock	—			—			249			—			249
Stockholders' Equity	14,669			3,063			10,269			(17,732		)	10,269
Total Liabilities and Stockholders' Equity	$	19,414		$	16,743		$	17,144		$	(18,318	)	$	34,983
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2012
	Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
	Subsidiaries			Subsidiaries									Balance
	(In millions)
Cash Flows from Operating Activities
Net Cash Provided/Used by Operating Activities	2,163			66			(902		)	(178		)	1,149
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(1,792		)	792			—			1,000			—
Acquisition of businesses, net of cash acquired	—			(17		)	(64		)	—			(81		)
Cash acquired in GenOn acquisition	—			983			—			—			983
Capital expenditures	(241		)	(3,091		)	(64		)	—			(3,396		)
Increase in restricted cash, net	(3		)	(63		)	—			—			(66		)
Decrease in restricted cash - U.S. DOE projects	—			121			43			—			164
Increase in notes receivable	(1		)	(21		)	(2		)	—			(24		)
Purchases of emission allowances, net of proceeds	(1		)	—			—			—			(1		)
Investments in nuclear decommissioning trust fund securities	(436		)	—			—			—			(436		)
Proceeds from sales of nuclear decommissioning trust fund securities	399			—			—			—			399
Proceeds from renewable energy grants	3			59			—			—			62
Proceeds from sale of assets, net	133			—			4			—			137
Equity investment in unconsolidated affiliate	(1		)	(12		)	(12		)	—			(25		)
Other	24			—			(2		)	—			22
Net Cash Used by Investing Activities	(1,916		)	(1,249		)	(97		)	1,000			(2,262		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			—			1,000			(1,000		)	—
Payment of dividends to preferred stockholders	—			—			(50		)	—			(50		)
Payment of intercompany dividends	(172		)	(6		)	—			178			—
Net (payments of)/receipts from acquired derivatives that include financing elements	(83		)	15			—			—			(68		)
Proceeds from issuance of long-term debt	42			2,105			1,018			—			3,165
Cash proceeds from sale of noncontrolling interest in subsidiary	—			347			—			—			347
Payment of debt issuance and hedging costs	—			(19		)	(16		)	—			(35		)
Payments of short and long-term debt	—			(82		)	(1,178		)	—			(1,260		)
Net Cash (Used)/Provided by Financing Activities	(213		)	2,360			774			(822		)	2,099
Effect of exchange rate changes on cash and cash equivalents	—			(4		)	—			—			(4		)
Net Increase/(Decrease) in Cash and Cash Equivalents	34			1,173			(225		)	—			982
Cash and Cash Equivalents at Beginning of Period	44			85			976			—			1,105
Cash and Cash Equivalents at End of Period	$	78		$	1,258		$	751		$	—		$	2,087
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2011
	Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
	Subsidiaries			Subsidiaries									Balance
	(In millions)
Operating Revenues
Total operating revenues	$	8,730		$	381		$	—		$	(32	)	$	9,079
Operating Costs and Expenses
Cost of operations	6,489			277			—			(21		)	6,745
Depreciation and amortization	843			40			13			—			896
Impairment losses	160			—			—			—			160
Selling, general and administrative	334			4			252			(4		)	586
Development activity expenses	—			11			46			—			57
Total operating costs and expenses	7,826			332			311			(25		)	8,444
Operating Income/(Loss)	904			49			(311		)	(7		)	635
Other Income
Equity in earnings/(losses) of consolidated subsidiaries	24			(7		)	593			(610		)	—
Equity in earnings of unconsolidated affiliates	10			25			—			—			35
Impairment charge on investment	(495		)	—			—			—			(495		)
Other income, net	2			13			4			—			19
Loss on debt extinguishment	—			—			(175		)	—			(175		)
Interest expense	(59		)	(56		)	(550		)	—			(665		)
Total other expense	(518		)	(25		)	(128		)	(610		)	(1,281		)
Income/(Loss) Before Income Taxes	386			24			(439		)	(617		)	(646		)
Income tax (benefit)/expense	(214		)	7			(636		)	—			(843		)
Net Income attributable to NRG Energy, Inc	$	600		$	17		$	197		$	(617	)	$	197
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Year Ended December 31, 2011
	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc.			Eliminations(a)			Consolidated Balance
							(Note Issuer)
	(In millions)
Net Income	$	600		$	17		$	197		$	(617	)	$	197
Other comprehensive income/(loss), net of tax
Unrealized loss on derivatives, net	(303		)	(27		)	(345		)	366			(309		)
Foreign currency translation adjustments, net	—			(2		)	—			—			(2		)
Available-for-sale securities, net	—			—			(1		)	—			(1		)
Defined benefit plan, net	(34		)	—			(12		)	—			(46		)
Other comprehensive loss	(337		)	(29		)	(358		)	366			(358		)
Comprehensive income/(loss) attributable to NRG Energy, Inc.	263			(12		)	(161		)	(251		)	(161		)
Dividends for preferred shares	—			—			9			—			9
Comprehensive income/(loss) available for common stockholders	$	263		$	(12	)	$	(170	)	$	(251	)	$	(170	)
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2011
	Guarantor			Non-Guarantor			NRG Energy, Inc.			Elimin-ations (a)			Consolidated
	Subsidiaries			Subsidiaries									Balance
	(In millions)
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities	621			294			1,620			(1,369		)	1,166
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	796			—			287			(1,083		)	—
Investment in subsidiaries	—			(1,300		)	—			1,300			—
Capital expenditures	(383		)	(1,882		)	(45		)	—			(2,310		)
Acquisition of business, net of cash acquired	—			(115		)	(262		)	—			(377		)
Increase in restricted cash	(5		)	(29		)	(1		)	—			(35		)
Increase in restricted cash to support equity requirements for U.S. DOE funded projects	—			(162		)	(53		)	—			(215		)
Decrease in notes receivable	—			12			—			—			12
Purchases of emission allowances, net of proceeds	(19		)	—			—			—			(19		)
Investments in nuclear decommissioning trust fund securities	(406		)	—			—			—			(406		)
Proceeds from sales of nuclear decommissioning trust fund securities	385			—			—			—			385
Proceeds from sale of assets, net	13			(6		)	—			—			7
Equity investment in unconsolidated affiliates, net	(2		)	(64		)	—			—			(66		)
Other	(2		)	(8		)	(13		)	—			(23		)
Net Cash Provided/(Used) by Investing Activities	377			(3,554		)	(87		)	217			(3,047		)
Cash Flows from Financing Activities
(Payments of)/proceeds from intercompany loans	(1,112		)	825			(796		)	1,083			—
Payment of intercompany dividends	(65		)	(4		)	—			69			—
Payment for dividends to preferred stockholders	—			—			(9		)	—			(9		)
Payments for acquired derivatives including financing elements	(83		)	—			—			—			(83		)
Payment for treasury stock	—			—			(430		)	—			(430		)
Installment proceeds from sale of noncontrolling interest of subsidiary	—			29			—			—			29
Proceeds from issuance of common stock	—			—			2			—			2
Proceeds from issuance of long-term debt	138			1,290			4,796			—			6,224
Proceeds from issuance of term loan for funded letter of credit facility	—			1,300			—			—			1,300
Increase in restricted cash supporting funded letter of credit facility	—			—			(1,300		)	—			(1,300		)
Payment of debt issuance and hedging costs	—			(92		)	(115		)	—			(207		)
Payments of short and long-term debt	—			(116		)	(5,377		)	—			(5,493		)
Net Cash (Used)/Provided by Financing Activities	(1,122		)	3,232			(3,229		)	1,152			33
Effect of exchange rate changes on cash and cash equivalents	—			2			—			—			2
Net Decrease in Cash and Cash Equivalents	(124		)	(26		)	(1,696		)	—			(1,846		)
Cash and Cash Equivalents at Beginning of Period	168			111			2,672			—			2,951
Cash and Cash Equivalents at End of Period	$	44		$	85		$	976		$	—		$	1,105
(a)	All significant intercompany transactions have been eliminated in consolidation.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies Disclosure	'
Basis of Presentation	'
	The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
Principles of Consolidation	'
	The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE should be consolidated.
Segment Reporting	'
	Segment Reporting
	Effective June 2013, the Company's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are primarily segregated based on the Retail Business, conventional power generation, alternative energy businesses, NRG Yield, and corporate activities.  Within NRG's conventional power generation, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, East, South Central, West and Other, which includes international businesses and maintenance services.  The Company's alternative energy segment includes solar and wind assets, excluding those in the NRG Yield segment, electric vehicle services and the carbon capture business.  NRG Yield includes certain of the Company's contracted generation assets including three natural gas or dual-fired facilities, eight utility-scale solar and wind generation facilities, two portfolios of distributed solar facilities and thermal infrastructure assets.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Funds Deposited by Counterparties	'
	Funds Deposited by Counterparties
	Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some 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 general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge 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. Changes in funds deposited by counterparties are closely associated with the Company's operating activities, and are classified as an operating activity in the Company's consolidated statements of cash flows.
Restricted Cash	'
	Restricted Cash
	Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments as well as to fund required equity contributions, per the restrictions of the debt agreements.
Trade Receivables and Allowance for Doubtful Accounts	'
	Trade Receivables and Allowance for Doubtful Accounts
	Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its Retail Business, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. The Retail Business writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.
Inventory	'
	Inventory
	Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at a weighted average cost, since the Company expects to recover these costs in the ordinary course of business. The Company removes these inventories when they are used for repairs, maintenance or capital projects. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Property, plant and equipment are stated at cost; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation other than nuclear fuel is computed using the straight-line method, while nuclear fuel is amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.
Asset Impairments	'
	Asset Impairments
	Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets and present value techniques.
	Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value.
Project Development Costs and Capitalized Interest	'
	and Capitalized Interest
	Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset.
	Development activity expenses include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
	Development activity expenses also include selling, general, and administrative expenses associated with the current operations of certain developing businesses including residential solar, electric vehicles, waste-to-energy, carbon capture and other emerging technologies. The revenue associated with these businesses was immaterial for the years ended December 31, 2013, 2012, and 2011. When it is determined that a business will remain an ongoing part of the Company's operations or when operating revenues become material relative to the operating costs of the underlying business, the Company no longer classifies a business as a development activity.
	Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2013, 2012, and 2011, was $64 million, $104 million, and $80 million, respectively.
	When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
Debt Issuance Costs	'
	Debt Issuance Costs
	Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt.
Intangible Assets	'
	Intangible Assets
	Intangible assets represent contractual rights held by NRG. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, development rights, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, NRG also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis.
	Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. NRG had no intangible assets with indefinite lives recorded as of December 31, 2013.
	Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.
Goodwill	'
	Goodwill
	In accordance with ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable.
	In September 2011, the FASB issued ASU No. 2011-08, Intangibles - Goodwill and Other (Topic 350) Testing Goodwill for Impairment, or ASU No. 2011-08. The objective of ASU 2011-08 is to simplify how entities test goodwill for impairment. The amendments in ASU No. 2011-08 permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. The Company adopted the provisions of ASU No. 2011-08, effective January 1, 2011, with no impact on its results of operations, financial position or cash flows.
	In the absence of sufficient qualitative factors, goodwill impairment is determined using a two step process:
		Step one —	Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two.
		Step two —	Compare the implied fair value of the reporting unit's goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds fair value, an impairment charge is recognized for the sum of such excess.
Income Taxes	'
	Income Taxes
	NRG accounts for income taxes using the liability method in accordance with ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
	NRG has two categories of income tax expense or benefit — current and deferred, as follows:
	•	Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and
	•	Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income.
	NRG reports some of the Company's revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. NRG measures the Company's deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in our estimate of future taxable income, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized.
	NRG reduces its current income tax expense in the consolidated statement of operations for any investment tax credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently amortized to earnings on a straight-line basis over the useful life of each underlying property.
	The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.
	In accordance with ASC 805 and as discussed further in Note 19, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.
Revenue Recognition	'
	Revenue Recognition
	Energy — Both physical and financial transactions are entered into to optimize the financial performance of NRG's generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.
	Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.
	Sale of Emission Allowances — NRG records the Company's bank of emission allowances as part of the Company's intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. NRG records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.
	Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes.
	Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $166 million, $151 million and $186 million for the years ended December 31, 2013, 2012, and 2011, respectively. These revenues represent the sale of excess supply to third parties in the market.
	Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. NRG recorded receivables for unbilled revenues of $356 million, $338 million and $318 million as of December 31, 2013, 2012, and 2011, respectively, for retail energy sales and services.
	PPAs — Certain of the Company's revenues are currently obtained through PPAs or other contractual arrangements. All of these PPAs are recorded as operating leases in accordance with ASC 840, Leases, or ASC 840. ASC 840 requires minimum lease payments received to be amortized over the term of the lease and contingent rentals are recorded when the achievement of the contingency becomes probable. These leases have no minimum lease payments and all the rent is recorded as contingent rent on an actual basis when the electricity is delivered. The contingent rental income recognized in the years ended December 31, 2013, 2012, and 2011 was $400 million, $130 million, and $27 million, respectively.
Gross Receipts and Sales Taxes	'
	Gross Receipts and Sales Taxes
	In connection with its Retail Business, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2013, 2012, and 2011, NRG's revenues and cost of operations included gross receipts taxes of $88 million, $79 million, and $78 million respectively. Additionally, the Retail Business records sales taxes collected from its taxable customers and remitted to the various governmental entities on a net basis, thus, there is no impact on the Company's consolidated statement of operations.
Derivative Financial Instruments	'
	Derivative Financial Instruments
	NRG accounts for derivative financial instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges, if elected for hedge accounting, are either:
	•	Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or
	•	Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings.
	NRG's primary derivative instruments are power sales contracts, fuels purchase contracts, other energy related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, NRG assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Hedge accounting will also be discontinued on contracts related to commodity price risk previously accounted for as cash flow hedges when it is probable that delivery will not be made against these contracts. In this case, the gain or loss previously deferred in accumulated OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until the underlying hedged item is delivered.
	Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
	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.
Foreign Currency Translation and Transaction Gains and Losses	'
	Foreign Currency Translation and Transaction Gains and Losses
	The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's statements of operations. For the years ended December 31, 2013, 2012, and 2011, amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2013, 2012, and 2011 were $15 million, $53 million and $72 million, respectively.
Concentrations of Credit Risk	'
	Concentrations of Credit Risk
	Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 4, Fair Value of Financial Instruments, for a further discussion of derivative concentrations.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments
	The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payables, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 4, Fair Value of Financial Instruments for a further discussion of fair value of financial instruments.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	NRG accounts for its AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.
	Upon initial recognition of a liability for an ARO, NRG capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 13, Asset Retirement Obligations, for a further discussion of AROs.
Pensions	'
	Pensions and Other Postretirement Benefits
	NRG offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. NRG accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. NRG recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of NRG's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. NRG's actuarial consultants determine assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.
	NRG measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820.
Stock-Based Compensation	'
	Stock-Based Compensation
	NRG accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718. The fair value of the Company's non-qualified stock options and performance units are estimated on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of NRG's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award.
Investments Accounted for by the Equity Method	'
	Investments Accounted for by the Equity Method
	NRG has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NRG from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates.
Marketing and Advertising Costs	'
	Marketing and Advertising Costs
	The Company expenses its advertising and marketing costs as incurred. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Marketing and advertising expenses included within selling, general and administrative expense for the years ended December 31, 2013, 2012, and 2011 were $195 million, $197 million, and $127 million respectively.
Business Combinations	'
	Business Combinations
	The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
Use of Estimates	'
	Use of Estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
	In recording transactions and balances resulting from business operations, NRG uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, and the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications	'
	Reclassifications
	Certain prior-year amounts have been reclassified for comparative purposes.
Nuclear Decommissioning Policy	'
	NRG accounts for the nuclear decommissioning trust fund in accordance with ASC 980, Regulated Operations, or ASC 980 because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.
Retail	'
Summary of Significant Accounting Policies Disclosure	'
Cost of Energy for Retail Operations	'
	Cost of Energy for Retail Operations
	The cost of energy for electricity sales and services to retail customers is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ($90 million, $97 million and $87 million as of December 31, 2013, 2012, and 2011, respectively) was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.

Nature_of_Business_Tables

Nature of Business (Tables)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Schedule of Global Generation Portfolio by Operating Segment	'
	The following table summarizes NRG's global generation portfolio by operating segment, which includes 88 fossil fuel and nuclear plants, eleven Utility Scale Solar facilities and four wind farms, as well as Distributed Solar facilities. Also included is one Utility Scale Solar facility and additional Distributed Solar facilities currently under construction. All Utility Scale Solar and Distributed Solar facilities are described in megawatts on an alternating current basis. MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units:
		Fossil Fuel, Nuclear, and Renewable
		(In MW)
	Generation Type	Texas	East	South Central	West	Alternative Energy		NRG Yield		Total Domestic		Other (Inter-national)	Total Global
	Natural gas	5,917	7,651	3,817	6,779	—		843		25,007		—	25,007
	Coal	4,193	6,879	1,496	—	—		—		12,568		605	13,173
	Oil(a)	—	5,531	—	—	—		190		5,721		—	5,721
	Nuclear	1,176	—	—	—	—		—		1,176		—	1,176
	Wind	—	—	—	—	347		101		448		—	448
	Utility Scale Solar	—	—	—	—	836		303		1,139		—	1,139
	Distributed Solar	—	—	—	—	37		10		47		—	47
	Total generation capacity	11,286	20,061	5,313	6,779	1,220		1,447		46,106		605	46,711
	Capacity attributable to noncontrolling interest	—	—	—	—	(331	)	(499	)	(830	)	—	(830	)
	Total net generation capacity	11,286	20,061	5,313	6,779	889		948		45,276		605	45,881
	Under Construction
	Utility Scale Solar	—	—	—	—	26		—		26		—	26
	Distributed Solar	—	—	—	—	6		—		6		—	6
	Total under construction	—	—	—	—	32		—		32		—	32

Business_Acquisitions_and_Disp1

Business Acquisitions and Dispositions (Tables) (GenOn Energy)	12 Months Ended
	Dec. 31, 2013
GenOn Energy	'
Business Acquisition	'
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	'
	The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of the acquisition date as well as adjustments made through December 13, 2013 to the amounts initially recorded in 2012 due to the ongoing evaluation of initial estimates. The measurement period adjustments were recorded as an adjustment to the gain on bargain purchase and did not have a significant impact on the Company's consolidated cash flows or financial position in any period. The purchase price of $2.2 billion was allocated as follows:
	(In millions)	Amounts Recognized		Measurement Period Adjustments			Amounts Recognized
		as of Acquisition Date					as of Acquisition Date
		(as previously reported)					(as adjusted)
	Assets
	Cash	$	983	$	—		$	983
	Current and non-current assets	1,385		28			1,413
	Property, plant and equipment	3,936		(115		)	3,821
	Derivative assets	1,157		—			1,157
	Deferred income taxes	2,265		(58		)	2,207
	Total assets acquired	$	9,726	$	(145	)	$	9,581
	Liabilities
	Current and non-current liabilities	$	1,312	$	54		$	1,366
	Out-of-market contracts and leases	1,064		62			1,126
	Derivative liabilities	399		—			399
	Long-term debt and capital leases	4,203		3			4,206
	Total liabilities assumed	6,978		119			7,097
	Net assets acquired	2,748		(264		)	2,484
	Consideration paid	2,188					2,188
	Gain on bargain purchase	$	560	$	(264	)	$	296

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value of Financial Instruments Disclosure [Abstract]	'
Estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value	'
	The estimated carrying values and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:
		As of December 31,
		2013				2012
		Carrying Amount		Fair Value		Carrying Amount			Fair Value
		(In millions)
	Assets
	Notes receivable (a)	$	99	$	99	$	88		$	88
	Liabilities
	Long-term debt, including current portion	16,804		17,222		15,866			16,492
Assets and liabilities measured and recorded at fair value on the consolidated balance sheets on a recurring basis	'
	The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
		As of December 31, 2013
		Fair Value
		Level 1		Level 2		Level 3			Total
		(In millions)
	Investment in available-for-sale securities (classified within other non-current assets):
	Debt securities	$	—	$	—	$	16		$	16
	Available-for-sale securities	2		—		—			2
	Other (a)	37		—		10			47
	Nuclear trust fund investments:
	Cash and cash equivalents	26		—		—			26
	U.S. government and federal agency obligations	40		5		—			45
	Federal agency mortgage-backed securities	—		62		—			62
	Commercial mortgage-backed securities	—		14		—			14
	Corporate debt securities	—		70		—			70
	Equity securities	276		—		56			332
	Foreign government fixed income securities	—		2		—			2
	Other trust fund investments:
	U.S. government and federal agency obligations	1		—		—			1
	Derivative assets:
	Commodity contracts	346		1,126		147			1,619
	Interest rate contracts	—		20		—			20
	Total assets	$	728	$	1,299	$	229		$	2,256
	Derivative liabilities:
	Commodity contracts	$	216	$	831	$	134		$	1,181
	Interest rate contracts	—		69		—			69
	Total liabilities	$	216	$	900	$	134		$	1,250
	(a)	Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for some key and highly compensated employees and a total return swap that does not meet the definition of a derivative.
		As of December 31, 2012
		Fair Value
		Level 1		Level 2		Level 3			Total
		(In millions)
	Investment in available-for-sale securities (classified within other non-current assets):
	Debt securities	$	—	$	—	$	12		$	12
	Other (a)	22		—		—			22
	Nuclear trust fund investments:
	Cash and cash equivalents	10		—		—			10
	U.S. government and federal agency obligations	33		—		—			33
	Federal agency mortgage-backed securities	—		59		—			59
	Commercial mortgage-backed securities	—		9		—			9
	Corporate debt securities	—		80		—			80
	Equity securities	233		—		47			280
	Foreign government fixed income securities	—		2		—			2
	Other trust fund investments:
	U.S. government and federal agency obligations	1		—		—			1
	Derivative assets:
	Commodity contracts	1,457		1,711		135			3,303
	Interest rate contracts	—		3		—			3
	Total assets	$	1,756	$	1,864	$	194		$	3,814
	Derivative liabilities:
	Commodity contracts	$	1,144	$	1,047	$	147		$	2,338
	Interest rate contracts	—		143		—			143
	Total liabilities	$	1,144	$	1,190	$	147		$	2,481
	(a)	Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for some key and highly compensated employees.
Reconciliation of beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs	'
	The following tables reconcile, for the years ended December 31, 2013, and 2012, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:
		For the Year Ended December 31, 2013
		Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
		Debt		Other		Trust Fund			Derivatives (a)			Total
		Securities				Investments
		(In millions)
	Beginning balance as of January 1, 2013	$	12	$	—	$	47		$	(12	)	$	47
	Total gains and losses (realized/unrealized):
	Included in OCI	4		—		—			—			4
	Included in earnings	—		—		—			(12		)	(12		)
	Included in nuclear decommissioning obligations	—		—		10			—			10
	Purchases	—		10		2			4			16
	Sales	—		—		(3		)	—			(3		)
	Transfers into Level 3 (b)	—		—		—			6			6
	Transfers out of Level 3 (b)	—		—		—			27			27
	Ending balance as of December 31, 2013	$	16	$	10	$	56		$	13		$	95
	Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2013	$	—	$	—	$	—		$	1		$	1
	(a)	Consists of derivatives assets and liabilities, net.
	(b)	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
		For the Year Ended December 31, 2012
		Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
		Debt		Trust Fund		Derivatives (a)			Total
		Securities		Investments
		(In millions)
	Beginning balance as of January 1, 2012	$	7	$	42	$	8		$	57
	Total gains and losses (realized/unrealized):
	Included in OCI	5		—		—			5
	Included in earnings	—		—		(13		)	(13		)
	Included in nuclear decommissioning obligations	—		5		—			5
	Purchases	—		—		8			8
	Contracts acquired in GenOn acquisition	—		—		18			18
	Transfers into Level 3 (b)	—		—		(33		)	(33		)
	Transfer out of Level 3 (b)	—		—		—			—
	Ending balance as of December 31, 2012	$	12	$	47	$	(12	)	$	47
	Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2012	$	—	$	—	$	(3	)	$	(3	)
	(a)	Consists of derivatives assets and liabilities, net.
	(b)	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
Net counterparty credit exposure by industry sector and by counterparty credit quality	'
	The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. 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. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.
	Category	Net Exposure (a)
		(% of Total)
	Financial institutions	52	%
	Utilities, energy merchants, marketers and other	29
	Coal and emissions	1
	ISOs	18
	Total	100	%
	Category	Net Exposure (a)
		(% of Total)
	Investment grade	94	%
	Non-Rated	6
	Total	100	%
	(a)	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.

Accounting_for_Derivative_Inst1

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting for Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity	'
	The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2013 and 2012. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.
			Total Volume
	Commodity	Units	December 31, 2013				December 31, 2012
			(In millions)
	Emissions	Short Ton	—				(1		)
	Coal	Short Ton	51				37
	Natural Gas	MMBtu	(166		)		(413		)
	Oil	Barrel	1				1
	Power	MWh	(27		)		(14		)
	Interest	Dollars	$	1,444			$	2,612
Fair value within the derivative instrument valuation on the balance sheets	'
	The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:
		Fair Value
		Derivative Assets								Derivative Liabilities
	(In millions)	December 31, 2013				December 31, 2012				December 31, 2013			December 31, 2012
	Derivatives Designated as Cash Flow or Fair Value Hedges:
	Interest rate contracts current	$	—			$	—			$	35		$	29
	Interest rate contracts long-term	14				3				29			96
	Commodity contracts current	—				—				1			3
	Commodity contracts long-term	—				—				1			1
	Total Derivatives Designated as Cash Flow or Fair Value Hedges	14				3				66			129
	Derivatives Not Designated as Cash Flow or Fair Value Hedges:
	Interest rate contracts current	—				—				4			7
	Interest rate contracts long-term	6				—				1			11
	Commodity contracts current	1,328				2,644				1,015			1,942
	Commodity contracts long-term	291				659				164			392
	Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	1,625				3,303				1,184			2,352
	Total Derivatives	$	1,639			$	3,306			$	1,250		$	2,481
Offsetting of derivatives by counterparty master agreement level and collateral received or paid	'
	The following table summarizes the offsetting derivatives by counterparty master agreement level and collateral received or paid:
		Gross Amounts Not Offset in the Statement of Financial Position
		Gross Amounts of Recognized Assets/Liabilities				Derivative Instruments				Cash Collateral (Held)/Posted			Net Amount
	As of December 31, 2013	(in millions)
	Commodity contracts:
	Derivative assets	$	1,619			$	(1,032	)		$	(62	)	$	525
	Derivative liabilities	(1,181		)		1,032				18			(131		)
	Total commodity contracts	438				—				(44		)	394
	Interest rate contracts:
	Derivative assets	20				(12		)		—			8
	Derivative liabilities	(69		)		12				—			(57		)
	Total interest rate contracts	(49		)		—				—			(49		)
	Total derivative instruments	$	389			$	—			$	(44	)	$	345
		Gross Amounts Not Offset in the Statement of Financial Position
		Gross Amounts of Recognized Assets/Liabilities				Derivative Instruments				Cash Collateral (Held)/Posted			Net Amount
	As of December 31, 2012	(in millions)
	Commodity contracts:
	Derivative assets	$	3,303			$	(2,024	)		$	(374	)	$	905
	Derivative liabilities	(2,338		)		2,024				28			(286		)
	Total commodity contracts	965				—				(346		)	619
	Interest rate contracts:
	Derivative assets	3				—				—			3
	Derivative liabilities	(143		)		—				—			(143		)
	Total interest rate contracts	(140		)		—				—			(140		)
	Total derivative instruments	$	825			$	—			$	(346	)	$	479
Effects of ASC 815 on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax	'
	The following tables summarize the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
		Year Ended December 31, 2013
		Energy				Interest				Total
		Commodities				Rate
		(In millions)
	Accumulated OCI balance at December 31, 2012	$	41			$	(72	)		$	(31	)
	Reclassified from accumulated OCI to income:
	Due to realization of previously deferred amounts	(51		)		20				(31		)
	Mark-to-market of cash flow hedge accounting contracts	9				30				39
	Accumulated OCI balance at December 31, 2013, net of $14 tax	(1		)		(22		)		(23		)
	Losses expected to be realized from OCI during the next 12 months, net of $8 tax	$	(1	)		$	(14	)		$	(15	)
	There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2013.
		Year Ended December 31, 2012
		Energy				Interest				Total
		Commodities				Rate
		(In millions)
	Accumulated OCI balance at December 31, 2011	$	188			$	(56	)		$	132
	Reclassified from accumulated OCI to income:
	Due to realization of previously deferred amounts	(144		)		23				(121		)
	Mark-to-market of cash flow hedge accounting contracts	(3		)		(39		)		(42		)
	Accumulated OCI balance at December 31, 2012, net of $7 tax	$	41			$	(72	)		$	(31	)
	Losses recognized in income from the ineffective portion of cash flow hedges	$	(51	)		$	—			$	(51	)
		Year Ended December 31, 2011
		Energy				Interest				Total
		Commodities				Rate Contracts
		(In millions)
	Accumulated OCI balance at December 31, 2010	$	488			$	(47	)		$	441
	Reclassified from accumulated OCI to income:
	Due to realization of previously deferred amounts	(374		)		12				(362		)
	Mark-to-market of cash flow hedge accounting contracts	74				(21		)		53
	Accumulated OCI balance at December 31, 2011, net of $87 tax	$	188			$	(56	)		$	132
	Gains recognized in income from the ineffective portion of cash flow hedges	$	28			$	3			$	31
Pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges and trading activity on the Company's statement of operations	'
	The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges, and trading activity on NRG's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.
		Year Ended December 31,
		2013				2012				2011
		(In millions)
	Unrealized mark-to-market results
	Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(105	)		$	(247	)		$	54
	Reversal of (gain)/loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions	(357		)		20				107
	Net unrealized gains/(losses) on open positions related to economic hedges	177				10				(33		)
	(Losses)/gains on ineffectiveness associated with open positions treated as cash flow hedges	—				(51		)		28
	Total unrealized mark-to-market (losses)/gains for economic hedging activities	(285		)		(268		)		156
	Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(50		)		(60		)		21
	Net unrealized gains on open positions related to trading activity	7				46				42
	Total unrealized mark-to-market (losses)/gains for trading activity	(43		)		(14		)		63
	Total unrealized (losses)/gains	$	(328	)		$	(282	)		$	219
		Year Ended December 31,
		2013				2012				2011
		(In millions)
	Unrealized (losses)/gains included in operating revenues	$	(621	)		$	(464	)		$	388
	Unrealized gains/(losses) included in cost of operations	293				182				(169		)
	Total impact to statement of operations — energy commodities	$	(328	)		$	(282	)		$	219
	Total impact to statement of operations — interest rate contracts	$	15			$	(8	)		$	2

Nuclear_Decommissioning_Trust_1

Nuclear Decommissioning Trust Fund (Tables)	12 Months Ended
	Dec. 31, 2013
Nuclear Decommissioning Trust Fund Disclosure [Abstract]	'
Summary of aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the nuclear decommissioning trust fund	'
	The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
		As of December 31, 2013										As of December 31, 2012
	(In millions, except otherwise noted)	Fair			Unrealized			Unrealized			Weighted-	Fair		Unrealized		Weighted-
		Value			Gains			Losses			average	Value		Gains (a)		average
											maturities					maturities
											(in years)					(in years)
	Cash and cash equivalents	$	26		$	—		$	—		—	$	10	$	—	—
	U.S. government and federal agency obligations	45			1			1			9	33		2		10
	Federal agency mortgage-backed securities	62			1			1			24	59		2		23
	Commercial mortgage-backed securities	14			—			—			29	9		—		30
	Corporate debt securities	70			1			1			9	80		4		11
	Equity securities	332			204			—			—	280		143		—
	Foreign government fixed income securities	2			—			—			9	2		—		6
	Total	$	551		$	207		$	3			$	473	$	151
Summary of proceeds from sales of available-for-sale securities and the related realized gains and losses	'
	The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.
		Year Ended December 31,
		2013			2012			2011
		(In millions)
	Realized gains	$	25		$	12		$	4
	Realized losses	(8		)	(7		)	(3		)
	Proceeds from sale of securities	488			399			385

Inventory_Tables

Inventory (Tables)	12 Months Ended
	Dec. 31, 2013
Inventory Disclosure [Abstract]	'
Schedule of Inventory	'
	Inventory consisted of:
		As of December 31,
		2013		2012
		(In millions)
	Fuel oil	$	259	$	181
	Coal/Lignite	290		405
	Natural gas	15		12
	Spare parts	316		301
	Other	18		4
	Total Inventory	$	898	$	903

Notes_Receivable_Tables

Notes Receivable (Tables)	12 Months Ended
	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]	'
Schedule of NRG's notes receivable and capital leases	'
	Notes receivable primarily consisted of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. NRG's notes receivable and capital leases were as follows:
		As of December 31,
		2013		2012
		(In millions)
	Notes receivable — non-affiliates (a)	$	97	$	82
	Notes receivable — affiliate
	Avenal Solar Holdings LLC, indefinite maturity date, 4.5% (b)	2		6
	Total notes receivable	99		88
	Less current maturities(c)	26		9
	Total notes receivable — noncurrent	$	73	$	79
	(a)	Primarily relates to Agua Caliente, Alpine, Borrego, El Segundo Energy Center and CVSR's agreements with their respective transmission owners to provide financing for required network upgrades. The notes will be repaid within a five year period following the date each facility reaches commercial operations.
	(b)	NRG entered into a long-term $35 million note receivable facility with Avenal Solar Holdings LLC, to fund project liquidity needs in 2011.
	(c)	The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
NRG's major classes of property, plant and equipment	'
	NRG's major classes of property, plant, and equipment were as follows:
		As of December 31,						Depreciable
		2013			2012			Lives
		(In millions)
	Facilities and equipment	$	22,087		$	19,571		1-40 Years
	Land and improvements	801			793
	Nuclear fuel	463			414			5 Years
	Office furnishings and equipment	298			355			2-10 Years
	Construction in progress	2,775			4,428
	Total property, plant, and equipment	26,424			25,561
	Accumulated depreciation	(6,573		)	(5,408		)
	Net property, plant, and equipment	$	19,851		$	20,153

Goodwill_an_Other_Intangibles_

Goodwill an Other Intangibles (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill and Other Intangibles Disclosure [Abstract]	'
Summary of the components of NRG's intangible assets subject to amortization	'
	The following tables summarize the components of NRG's intangible assets subject to amortization:
								Contracts
	Year Ended December 31, 2013	Emission			Development			Energy			Fuel			Customer			Customer			Marketing Partnerships			Trade			Other			Total
		Allowances			Rights			Supply									Relationships						Names
		(In millions)
	1-Jan-13	$	793		$	24		$	54		$	72		$	859		$	640		$	88		$	318		$	68		$	2,916
	Purchases	76			—			—			—			—			14			—			—			28			118
	Acquisition of businesses	—			—			—			—			—			89			—			—			10			99
	Usage	—			—			—			—			—			—			—			—			(14		)	(14		)
	Other	2			(5		)	—			—			—			—			—			—			1			(2		)
	31-Dec-13	871			19			54			72			859			743			88			318			93			3,117
	Less accumulated amortization	(433		)	—			(36		)	(61		)	(847		)	(487		)	(12		)	(93		)	(8		)	(1,977		)
	Net carrying amount	$	438		$	19		$	18		$	11		$	12		$	256		$	76		$	225		$	85		$	1,140
								Contracts
	Year Ended December 31, 2012	Emission			Development			Energy			Fuel			Customer			Customer			Marketing Partnerships			Trade			Other			Total
		Allowances			Rights			Supply									Relationships						Names
		(In millions)
	1-Jan-12	$	783		$	24		$	54		$	72		$	859		$	634		$	88		$	318		$	39		$	2,871
	Purchases	18			—			—			—			—			—			—			—			18			36
	Acquisition of businesses	53			—			—			—			—			6			—			—			10			69
	Usage	—			—			—			—			—			—			—			—			(13		)	(13		)
	Sales	(4		)	—			—			—			—			—			—			—			—			(4		)
	Write-off of fully amortized balances	(56		)	—			—			—			—			—			—			—			—			(56		)
	Other	(1		)	—			—			—			—			—			—			—			14			13
	31-Dec-12	793			24			54			72			859			640			88			318			68			2,916
	Less accumulated amortization(a)	(329		)	—			(30		)	(59		)	(794		)	(415		)	(4		)	(72		)	(3		)	(1,706		)
	Net carrying amount	$	464		$	24		$	24		$	13		$	65		$	225		$	84		$	246		$	65		$	1,210
	(a) Adjusted for write-off of fully amortized emission allowances of $56 million
Schedule of NRG's amortization of intangible assets	'
	The following table presents NRG's amortization of intangible assets for each of the past three years:
		Years Ended December 31,
	Amortization	2013			2012			2011
		(In millions)
	Emission allowances	$	104		$	50		$	66
	Energy supply contracts	6			5			4
	Fuel contracts	2			2			2
	Customer contracts	53			119			185
	Customer relationships	72			98			109
	Marketing partnerships	8			4			—
	Trade names	29			30			22
	Other	5			2			—
	Total amortization	$	279		$	310		$	388
Schedule of estimated amortization of NRG's intangible assets for each of the next five years	'
	The following table presents estimated amortization of NRG's intangible assets for each of the next five years:
								Contracts
	Year Ended December 31,	Emission			Development			Energy			Fuel			Customer			Customer			Marketing Partnerships			Trade			Total
		Allowances			Rights			Supply									Relationships						Names
		(In millions)
	2014	$	77		$	1		$	6		$	2		$	1		$	61		$	15		$	21		$	184
	2015	65			1			6			2			1			45			14			21			155
	2016	64			1			6			2			1			31			9			21			135
	2017	65			1			—			—			1			21			5			21			114
	2018	68			1			—			—			1			10			5			21			106
Schedule of weighted average remaining amortization period related to NRG's intangible assets	'
	The following table presents the weighted average remaining amortization period related to NRG's intangible assets purchased in 2013 business acquisitions:
	As of December 31, 2013		Customer Relationships
			(In years)
	Weighted average remaining amortization period		28
Summary of estimated amortization related to NRG's out-of-market contracts	'
	The following table summarizes the estimated amortization related to NRG's out-of-market contracts:
	Year Ended December 31,		Power Contracts			Leases		Gas Transportation			Total
		(In millions)
	2014		$	17		39		$	36		$	92
	2015		17			39		37			93
	2016		18			39		42			99
	2017		18			39		37			94
	2018		19			39		32			90

Debt_and_Capital_Leases_Tables

Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Instrument	'
Long-term debt and capital leases	'
	Long-term debt and capital leases consisted of the following:
		As of December 31,
		2013				2012				Interest Rate % (a)
		(In millions except rates)
	NRG Recourse Debt:
	Senior notes, due 2018	$	1,130			$	1,200			7.625
	Senior notes, due 2019	800				800				7.625
	Senior notes, due 2019	602				693				8.5
	Senior notes, due 2020	1,062				1,100				8.25
	Senior notes, due 2021	1,128				1,128				7.875
	Senior notes, due 2023	990				990				6.625
	Term loan facility, due 2018	2,002				1,573				L+3.00/L+2.00
	Indian River Power LLC, tax exempt bonds, due 2040 and 2045	247				247				5.375 - 6.00
	Dunkirk Power LLC, tax exempt bonds, due 2042	59				59				5.875
	Fort Bend County, tax-exempt bonds, due 2038 and 2042	67				28				4.75
	Subtotal NRG Recourse Debt	8,087				7,818
	NRG Non-Recourse Debt:
	GenOn senior notes, due 2014	—				617				7.625
	GenOn senior notes, due 2017	782				800				7.875
	GenOn senior notes, due 2018	780				801				9.5
	GenOn senior notes, due 2020	621				631				9.875
	GenOn Americas Generation senior notes, due 2021	503				509				8.5
	GenOn Americas Generation senior notes, due 2031	435				437				9.125
	NRG Marsh Landing term loan, due 2017 and 2023(b)	473				390				L+2.75 - 3.00
	CVSR - High Plains Ranch II LLC, due 2014 and 2037(b)	1,104				786				0.611 - 3.579
	NRG West Holdings LLC, term loan, due 2023	512				350				L+2.25 - 2.75
	Agua Caliente Solar, LLC, due 2037	878				640				2.395 - 3.633
	Ivanpah Financing, due 2014 and 2038	1,575				1,437				1.116 - 4.256
	South Trent Wind LLC, due 2020	69				72				L+ 2.625
	NRG Peaker Finance Co. LLC, bonds, due 2019	154				173				L+1.07
	NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025(b)	127				137				5.95 - 7.31
	NRG Solar Alpine LLC, due 2014 and 2022(b)	221				2				L+2.25 - 2.50
	NRG Solar Borrego I LLC, due 2024 and 2038(b)	78				—				L+2.50/5.65
	NRG Solar Avra Valley LLC(b)	63				66				L+2.25
	TA - High Desert LLC, due 2014, 2023 and 2033	80				—				L+2.50/5.15
	NRG Solar Kansas South LLC, due 2014 and 2031	58				—				L+2.00 - 2.625
	Other	204				200				various
	Subtotal NRG Non-Recourse Debt	8,717				8,048
	Subtotal Long Term Debt	16,804				15,866
	Capital leases:
	Chalk Point capital lease, due 2015	10				14				8.19
	Other	3				3				various
	Subtotal Capital Leases	13				17
	Subtotal	16,817				15,883
	Less current maturities	1,050				147
	Total long-term debt and capital leases	$	15,767			$	15,736
	(a)	As of December 31, 2013, L+ equals 3 month LIBOR plus x%, with the exception of NRG Solar Alpine LLC cash grant loan and NRG Solar Kansas South LLC and TA - High Desert LLC cash grant bridge loan which are 1 month LIBOR plus x% and NRG Solar Kansas South LLC term loan which is 3 month LIBOR plus x%
	(b)	Debt related to projects in NRG Yield
	Long-term debt includes the following premiums/(discounts):
			As of December 31,
			2013				2012
			(in millions)
	Senior notes, due 2019		$	(5	)		$	(7	)
	Term loan facility, due 2018 (a)		(5		)		(3		)
	NRG Peaker Finance Co. LLC, bonds, due 2019 (b)		(11		)		(15		)
	GenOn senior notes, due 2014 (c)		—				42
	GenOn senior notes, due 2017 (c)		58				75
	GenOn senior notes, due 2018 (c)		104				126
	GenOn senior notes, due 2020 (c)		71				81
	GenOn Americas Generation senior notes, due 2021 (c)		53				59
	GenOn Americas Generation senior notes, due 2031 (c)		35				37
	Total premium/(discount)		$	300			$	395
	(a)	Discount of $1 million is related to current maturities in 2013 and 2012.
(b)	Discounts of $4 million and $5 million are related to current maturities in 2013 and 2012, respectively.
(c)	Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition, as described further in Note 3, Business Acquisitions and Dispositions.
Schedule of swaps related to project level debt	'
	The following table summarizes the swaps, some of which are forward starting as indicated, related to NRG's project level debt as of December 31, 2013.
	Non-Recourse Debt	% of Principal			Fixed Interest Rate			Floating Interest Rate		Notional Amount at		Effective Date	Maturity Date
										31-Dec-13
										(In millions)
	NRG Peaker Finance Co. LLC	100	%		6.673	%		3-mo. LIBOR + 1.07%		$	165	18-Jun-02	10-Jun-19
	NRG West Holdings LLC	75	%		2.417	%		3-mo. LIBOR		405		30-Nov-11	31-Aug-23
	South Trent Wind LLC	75	%		3.265	%		3-mo. LIBOR		51		June 15, 2010	June 14, 2020
	South Trent Wind LLC	75	%		4.95	%		3-mo. LIBOR		21		June 30, 2020	June 14, 2028
	NRG Solar Roadrunner LLC	75	%		4.313	%		3-mo. LIBOR		33		September 30, 2011	December 31, 2029
	NRG Solar Alpine LLC	85	%		2.744	%		3-mo. LIBOR		135		December 31, 2012	December 31, 2029
	NRG Solar Avra Valley LLC	90	%		2.333	%		3-mo. LIBOR		56		November 30, 2012	November 30, 2030
	NRG Marsh Landing	75	%		3.244	%		3-mo. LIBOR		472		June 28, 2013	June 30, 2023
	Other	75	%		various			various		104		various	various
Annual payments based on the maturities of NRG's debt	'
	Annual payments based on the maturities of NRG's debt, for the years ending after December 31, 2013, are as follows:
		(In millions)
	2014	$	1,045
	2015	254
	2016	270
	2017	1,034
	2018	4,035
	Thereafter	10,166
	Total	$	16,804
8.50% Senior notes, due 2019	'
Debt Instrument	'
Long-term debt and capital leases	'
	In addition, on or after June 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
	Redemption Period	Redemption
		Percentage
	June 15, 2014 to June 14, 2015	104.25	%
	June 15, 2015 to June 14, 2016	102.83	%
	June 15, 2016 to June 14, 2017	101.42	%
	June 15, 2017 and thereafter	100	%
Senior notes, due 2020	'
Debt Instrument	'
Long-term debt and capital leases	'
	In addition, on or after September 1, 2015, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
	Redemption Period	Redemption
		Percentage
	On or after September 1, 2015	104.125	%
	On or after September 1, 2016	102.75	%
	On or after September 1, 2017	101.375	%
	September 1, 2018 and thereafter	100	%
7.625% Senior notes, due 2019	'
Debt Instrument	'
Long-term debt and capital leases	'
	In addition, on or after May 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
	Redemption Period	Redemption
		Percentage
	May 15, 2014 to May 14, 2015	103.813	%
	May 15, 2015 to May 14, 2016	101.906	%
	May 15, 2016 and thereafter	100	%
Senior notes, due 2021	'
Debt Instrument	'
Long-term debt and capital leases	'
	In addition, on or after May 15, 2016, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
	Redemption Period	Redemption
		Percentage
	May 15, 2016 to May 14, 2017	103.938	%
	May 15, 2017 to May 14, 2018	102.625	%
	May 15, 2018 to May 14, 2019	101.313	%
	May 15, 2019 and thereafter	100	%
Senior notes, due 2023	'
Debt Instrument	'
Long-term debt and capital leases	'
	In addition, on or after September 15, 2017, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
	Redemption Period	Redemption
		Percentage
	September 15, 2017 to September 14, 2018	103.313	%
	September 15, 2018 to September 14, 2019	102.208	%
	September 15, 2019 to September 14, 2020	101.104	%
	September 15, 2020 and thereafter	100	%
GenOn senior notes, due 2020	'
Debt Instrument	'
Long-term debt and capital leases	'
	In addition, on or after October 15, 2015, GenOn may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption rate:
	Redemption Period	Redemption
		Percentage
	October 15, 2015 to October 14, 2016	104.938	%
	October 15, 2016 to October 14, 2017	103.292	%
	October 15, 2017 to October 14, 2018	101.646	%
	October 15, 2018 and thereafter	100	%
Ivanpah Financing, due 2014 and 2038	'
Debt Instrument	'
Borrowings under the Ivanpah Credit Agreement	'
	The following table reflects the borrowings under the Ivanpah Credit Agreement as of December 31, 2013:
		Maximum borrowings available under Ivanpah Credit Agreement				Amounts borrowed				Weighted average interest rate on amounts borrowed
		(In millions, except rates)
	Solar Partners I, due June 27, 2014 (a)	$	159			$	159			1.68	%
	Solar Partners I, due June 27, 2033	392				371				2.808	%
	Solar Partners II, due February 27, 2014 (a)	132				132				1.611	%
	Solar Partners II, due February 27, 2038	387				377				3.132	%
	Solar Partners VIII, due October 27, 2014 (a)	117				116				1.998	%
	Solar Partners VIII, due October 27, 2038	440				420				3.097	%
		$	1,627			$	1,575
	(a)	The cash portion of the loan is fully drawn; additional amounts will be utilized for capitalized interest.

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of company's ARO obligations and related additions, reductions and accretion	'
	The following table represents the balance of ARO obligations as of December 31, 2013, and 2012, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2013:
		(In millions)
	Balance as of December 31, 2012	$	646
	Revisions in estimates for current obligations	(77		)
	Additions	29
	Spending for current obligations	(5		)
	Accretion — Expense	19
	Accretion — Nuclear decommissioning	17
	Balance as of December 31, 2013	$	629

Benefit_Plans_and_Other_Postre1

Benefit Plans and Other Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Annual net periodic benefit cost related to NRG's pension and other postretirement benefit plans	'
	The annual net periodic benefit cost related to NRG's pension and other postretirement benefit plans include the following components:
		Year Ended December 31,
		Pension Benefits
		2013				2012				2011
		(In millions)
	Service cost benefits earned	$	30			$	14			$	14
	Interest cost on benefit obligation	47				23				21
	Expected return on plan assets	(55		)		(23		)		(21		)
	Amortization of unrecognized net loss	9				4				—
	Curtailment	(1		)		—				—
	Net periodic benefit cost	$	30			$	18			$	14
		Year Ended December 31,
		Other Postretirement Benefits
		2013				2012				2011
		(In millions)
	Service cost benefits earned	$	4			$	2			$	2
	Interest cost on benefit obligation	9				6				6
	Amortization of unrecognized net loss	—				1				—
	Net periodic benefit cost	$	13			$	9			$	8
Pension benefit obligation, other post retirement benefit obligations and related plan assets for NRG plans on a combined basis	'
	A comparison of the pension benefit obligation, other postretirement benefit obligations and related plan assets for NRG's plans on a combined basis is as follows:
		As of December 31,
		Pension Benefits								Other Postretirement
										Benefits
		2013				2012				2013			2012
		(In millions)
	Benefit obligation at January 1	$	1,147			$	456			$	220		$	122
	Obligations assumed in the GenOn acquisition	—				596				—			87
	Service cost	30				14				4			2
	Interest cost	47				23				9			6
	Plan amendments	5				—				(4		)	(1		)
	Actuarial (gain)/loss	(125		)		75				(29		)	6
	Employee and retiree contributions	—				—				2			1
	Benefit payments	(43		)		(17		)		(11		)	(3		)
	Curtailment	(1		)		—				—			—
	Benefit obligation at December 31	1,060				1,147				191			220
	Fair value of plan assets at January 1	757				308				—			—
	Assets acquired in the GenOn acquisition	—				402				—			—
	Actual return on plan assets	116				41				—			—
	Employee contributions	—				—				2			1
	Employer contributions	50				23				9			2
	Benefit payments	(43		)		(17		)		(11		)	(3		)
	Fair value of plan assets at December 31	880				757				—			—
	Funded status at December 31 — excess of obligation over assets	$	(180	)		$	(390	)		$	(191	)	$	(220	)
Amounts recognized in NRG's balance sheets	'
	Amounts recognized in NRG's balance sheets were as follows:
		As of December 31,
		Pension Benefits								Other Postretirement
										Benefits
		2013				2012				2013			2012
		(In millions)
	Current liabilities	$	12			$	1			$	9		$	9
	Non-current liabilities	166				389				182			211
Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost	'
	Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows:
		As of December 31,
		Pension Benefits								Other Postretirement
										Benefits
		2013				2012				2013			2012
		(In millions)
	Unrecognized (gain)/loss	$	(57	)		$	140			$	(12	)	$	17
	Prior service cost/(credit)	4				(2		)		(6		)	(2		)
Other changes in plan assets and benefit obligations recognized in OCI	'
	Other changes in plan assets and benefit obligations recognized in OCI were as follows:
		Year Ended December 31,
		Pension								Other Postretirement
		Benefits								Benefits
		2013				2012				2013			2012
		(In millions)
	Unrecognized (gain)/loss	$	(188	)		$	56			$	(29	)	$	7
	Amortization of net actuarial gain	(9		)		(4		)		—			(1		)
	Prior service credit	5				—				(4		)	(1		)
	Curtailment	1				—				—			—
	Total recognized in other comprehensive loss	$	(191	)		$	52			$	(33	)	$	5
	Total recognized in net periodic pension cost and other comprehensive income	$	(161	)		$	71			$	(20	)	$	13
Balances of significant components of NRG's domestic pension plan	'
	The following table presents the balances of significant components of NRG's pension plan:
		As of December 31,
		Pension Benefits
		2013				2012
		(In millions)
	Projected benefit obligation	$	1,060			$	1,147
	Accumulated benefit obligation	967				1,024
	Fair value of plan assets	880				757
Fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy	'
	NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows:
		Fair Value Measurements as of December 31, 2013
		Quoted Prices in				Significant				Total
		Active Markets for				Observable Inputs
		Identical Assets				(Level 2)
		(Level 1)
		(In millions)
	Common/collective trust investment — U.S. equity	—				370				370
	Common/collective trust investment — non-U.S. equity	—				212				212
	Common/collective trust investment — fixed income	—				296				296
	Short-term investment fund	2				—				2
	Total	$	2			$	878			$	880
		Fair Value Measurements as of December 31, 2012
		Quoted Prices in				Significant				Total
		Active Markets for				Observable Inputs
		Identical Assets				(Level 2)
		(Level 1)
		(In millions)
	U.S. equity investment	$	—			$	26			$	26
	Non-U.S. equity investment	24				44				68
	Corporate bond investment — fixed income	—				32				32
	Common/collective trust investment — U.S. equity	—				290				290
	Common/collective trust investment — non-U.S. equity	—				111				111
	Common/collective trust investment — fixed income	—				228				228
	Short-term investment fund	—				2				2
	Total	$	24			$	733			$	757
Significant assumptions used to calculate NRG's benefit obligations and benefit expense	'
	The following table presents the significant assumptions used to calculate NRG's benefit obligations:
		As of December 31,
		Pension Benefits						Other Postretirement Benefits
	Weighted-Average Assumptions	2013			2012			2013			2012
	Discount rate	4.99	%		4.16	%		5.06	%		4.31	%
	Rate of compensation increase	3.65	%		3.57	%		N/A			N/A
	Health care trend rate	—			—			8.5% grading to			8.0% grading to
								5.5% in 2019			5.0% in 2019
	The following table presents the significant assumptions used to calculate NRG's benefit expense:
		As of December 31,
		Pension Benefits									Other Postretirement Benefits
	Weighted-Average Assumptions	2013			2012			2011			2013		2012			2011
	Discount rate	4.16	%		4.95	%		5.47	%		4.31	%	5.15	%		5.77	%
	Expected return on plan assets	7.12	%		6.96	%		7.34	%		—		—			—
	Rate of compensation increase	3.57	%		4.34	%		4.4	%		—		—			—
	Health care trend rate	—			—			—			8.3% grading to		8.0% grading to			8.0% grading to
											5.3% in 2019		5.0% in 2019			5.0% in 2019
Target allocations of NRG's pension plan assets	'
	The target allocations of NRG's pension plan assets were as follows for the years ended December 31, 2013 and 2012:
	U.S. equity	38.5 - 45.5%
	Non-U.S. equity	16.5 - 28%
	U.S. fixed income	30 - 45%
Expected future benefit payments for each of the next five years and in the aggregate for the five years thereafter	'
	NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows:
						Other Postretirement Benefit
		Pension				Benefit Payments				Medicare Prescription Drug Reimbursements
		Benefit Payments
		(In millions)
	2014	$	60			$	9			$	—
	2015	53				10				—
	2016	58				10				—
	2017	59				10				—
	2018	63				11				—
	2019-2023	362				62				2
Effect of one-percentage-point change in assumed health care cost trend rates	'
	Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:
		1-Percentage-				1-Percentage-
		Point Increase				Point Decrease
		(In millions)
	Effect on total service and interest cost components	$	1			$	(1	)
	Effect on postretirement benefit obligation	14				(11		)
Amounts recognized in NRG's statement of fiancial position, statement of operations and accumulated OCI related to its interest in STP	'
	The Company has recognized the following in its statement of financial position, statement of operations and accumulated OCI related to its 44% interest in STP:
		As of December 31,
		Pension Benefits								Other Postretirement Benefits
		2013				2012				2013			2012
		(In millions)
	Funded status — STPNOC benefit plans	$	(42	)		$	(76	)		$	(52	)	$	(56	)
	Net periodic benefit costs	11				10				8			8
	Other changes in plan assets and benefit obligations recognized in other comprehensive income	(31		)		14				(10		)	1
Contributions to defined contribution plans	'
	The Company's contributions to these plans were as follows:
		Year Ended December 31,
		2013				2012 (a)				2011
		(In millions)
	Company contributions to defined contribution plans	$	34			$	24			$	24
	(a)	Includes contributions to former GenOn plans for the period of December 15, 2012 to December 31, 2012.

Capital_Structure_Tables

Capital Structure (Tables)	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Changes in NRG's common shares issued and outstanding	'
	The following table reflects the changes in NRG's common shares issued and outstanding for each period presented:
		Common
		Issued		Treasury			Outstanding
	Balance as of December 31, 2010	304,006,027		(56,808,672	)		247,197,355
	Shares issued under ESPP	—		120,127			120,127
	Shares issued from LTIP	177,693		—			177,693
	Share repurchases	—		(19,975,654	)		(19,975,654	)
	Balance as of December 31, 2011	304,183,720		(76,664,199	)		227,519,521
	Shares issued under ESPP	—		158,481			158,481
	Shares issued under LTIPs	996,262		—			996,262
	Shares issued through GenOn acquisition	93,932,634		—			93,932,634
	Balance as of December 31, 2012	399,112,616		(76,505,718	)		322,606,898
	Shares issued under ESPP	—		130,482			130,482
	Shares issued under LTIPs	2,014,164		—			2,014,164
	Share repurchases	—		(972,292	)		(972,292	)
	Balance as of December 31, 2013	401,126,780		(77,347,528	)		323,779,252
NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plans	'
	The following table summarizes NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plans as of December 31, 2013:
	Equity Instrument	Common Stock
		Reserve Balance
	3.625% Convertible perpetual preferred	16,000,000
	Long-term incentive plans	21,121,160
	Total	37,121,160
Dividends paid per common share	'
	The following table lists the dividends paid per common share during 2013 and 2012:
		First Quarter			Second Quarter				Third Quarter		Fourth Quarter
	2013	$	0.09		$	0.12			$	0.12	$	0.12
	2012	$	—		$	—			$	0.09	$	0.09

Investments_Accounted_for_by_t1

Investments Accounted for by the Equity Method and Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]	'
Summary NRG's equity method investments	'
	The following table summarizes NRG's equity method investments as of December 31, 2013:
	Name	Geographic Area	Economic
			Interest
	Avenal Solar Holdings LLC	United States	50	%
	GenConn Energy LLC	United States	50	%
	Saguaro Power Company	United States	50	%
	Sherbino I Wind Farm LLC	United States	50	%
	Texas Coastal Ventures, LLC	United States	50	%
	Sabine CoGen, LP	United States	50	%
	Sunora Energy Solutions I LLC	United States	50	%
	Gladstone Power Station	Australia	37.5	%
Undistributed earnings by equity investment	'
		As of December 31,
		2013			2012
		(In millions)
	Undistributed earnings from equity investments	$	94		$	149

Segment_Reporting_Tables

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment reporting information	'
		Year Ended December 31, 2013
					Conventional Power Generation
		Retail			Texas			East			South			West			Other			Alternative Energy			NRG Yield			Corporate			Eliminations			Total
											Central
		(In millions)
	Operating revenues(a)	$	6,241		$	2,106		$	3,209		$	874		$	475		$	153		$	233		$	313		$	7		$	(2,316	)	$	11,295
	Operating expenses	5,535			1,826			2,512			750			318			144			147			134			50			(2,307		)	9,109
	Depreciation and amortization	142			457			320			98			55			4			108			51			21			—			1,256
	Impairment charges	—			—			459			—			—			—			—			—						—			459
	Acquisition-related transaction and integration costs	—			—			—			—			—			—			—			—			128			—			128
	Operating income/(loss)	564			(177		)	(82		)	26			102			5			(22		)	128			(192		)	(9		)	343
	Equity in earnings/(loss) of unconsolidated affiliates	—			—			—			4			(11		)	6			(4		)	22			—			(10		)	7
	Impairment losses on investments	—			—			—			—			—			(99		)	—			—			—			—			(99		)
	Other income, net	—			1			28			1			1			3			2			2			74			(99		)	13
	Loss on debt extinguishment	—			—			—			—			—			—			—			—			(50		)	—			(50		)
	Interest expense	(2		)	(1		)	(85		)	(18		)	(14		)	—			(57		)	(35		)	(735		)	99			(848		)
	Income/(loss) before income taxes	562			(177		)	(139		)	13			78			(85		)	(81		)	117			(903		)	(19		)	(634		)
	Income tax (benefit)/expense	—			—			—			—			—			(29		)	—			8			(261		)	—			(282		)
	Net income/(loss)	$	562		$	(177	)	$	(139	)	$	13		$	78		$	(56	)	$	(81	)	$	109		$	(642	)	$	(19	)	$	(352	)
	Less: Net income attributable to noncontrolling interest	$	—		$	—		$	—		$	—		$	—		$	—		$	27		$	13		$	—		$	(6	)	$	34
	Net income/(loss) attributable to NRG Energy, Inc.	$	562		$	(177	)	$	(139	)	$	13		$	78		$	(56	)	$	(108	)	$	96		$	(642	)	$	(13	)	$	(386	)
	Balance sheet
	Equity investments in affiliates	—			—			5			17			(35		)	188			150			227			—			(99		)	453
	Capital expenditures(a)	30			119			181			88			136			15			818			116			73						1,576
	Goodwill	260			1,713			—			—			—			—			12			—			—			—			1,985
	Total assets	4,717			11,656			8,437			2,431			1,638			468			6,213			2,313			25,290			(29,261		)	33,902
	(b) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	9		$	2,058		$	87		$	16		$	4		$	64		$	23		$	—		$	7
	(a) Includes accruals.
		Year Ended December 31, 2012
					Conventional Power Generation
		Retail			Texas			East(d)			South(d)Central			West(d)			Other			Alternative Energy			NRG Yield			Corporate(d)			Eliminations			Total
		(In millions)
	Operating revenues(c)	$	5,772		$	2,074		$	854		$	807		$	259		$	173		$	125		$	175		$	17		$	(1,834	)	$	8,422
	Operating expenses	5,065			1,712			754			695			194			161			87			119			47			(1,819		)	7,015
	Depreciation and amortization	162			458			137			93			12			2			49			25			12			—			950
	Acquisition-related transaction and integration costs	—			—			—			—			—			—			—			—			107			—			107
	Operating income/(loss)	545			(96		)	(37		)	19			53			10			(11		)	31			(149		)	(15		)	350
	Equity in earnings/(loss) of unconsolidated affiliates	—			—			—			—			7			13			—			19			(2		)	—			37
	Impairment losses on investments	—			—			—			—			—			—			—			—			(2		)	—			(2		)
	Bargain purchase gain related to GenOn acquisition	—			—			—			—			—			—			—			—			296			—			296
	Other income, net	—			2			2			1			1			4			—			1			26			(18		)	19
	Loss on debt extinguishment	—			—			—			—			—			—			—			—			(51		)	—			(51		)
	Interest expense	(4		)	—			(20		)	(18		)	(2		)	(3		)	(26		)	(28		)	(578		)	18			(661		)
	Income/(loss) before income taxes	541			(94		)	(55		)	2			59			24			(37		)	23			(460		)	(15		)	(12		)
	Income tax expense/(benefit)	—			—			—			—			—			3			—			10			(340		)	—			(327		)
	Net income/(loss)	541			(94		)	(55		)	2			59			21			(37		)	13			(120		)	(15		)	315
	Less: Net income attributable to noncontrolling interest	—			—			—			—			—			—			20						—			—			20
	Net income/(loss) attributable to NRG Energy, Inc.	$	541		$	(94	)	$	(55	)	$	2		$	59		$	21		$	(57	)	$	13		$	(120	)	$	(15	)	$	295
	Balance sheet
	Equity investments in affiliates	$	—		$	—		$	7		$	19		$	27		$	322		$	163		$	220		$	10		$	(92	)	$	676
	Capital expenditures (e)	19			117			71			36			244			16			2,700			478			12			—			3,693
	Goodwill	231			1,713			—			—			—			—			12			—			—			—			1,956
	Total assets	$	3,122		$	10,988		$	6,972		$	1,935		$	1,313		$	442		$	5,367		$	1,964		$	28,330		$	(25,450	)	$	34,983
	(c) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	5		$	1,657		$	73		$	—		$	—		$	69		$	20		$	—		$	10
	(d) Includes GenOn results for the period December 15, 2012 to December 31, 2012.
	(e) Includes accruals.
		Year Ended December 31, 2011
					Conventional Power Generation
		Retail(f)(g)			Texas(f)			East(f)			South(f)			West(f)			Other(f)			Alternative Energy(f)			NRG Yield(f)			Corporate(f)			Eliminations			Total
											Central
					(In millions)
	Operating revenues	$	5,642		$	2,832		$	924		$	817		$	149		$	183		$	22		$	164		$	11		$	(1,665	)	$	9,079
	Operating expenses	5,113			1,910			859			703			92			178			62			114			30			(1,673		)	7,388
Depreciation and amortization	159			463			118			89			10			—			23			22			12			—			896
Impairment losses	—			160			—			—			—			—			—						—			—			160
Operating income/(loss)	370			299			(53		)	25			47			5			(63		)	28			(31		)	8			635
Equity in earnings of unconsolidated affiliates	—			—			—			—			9			9			4			13			—			—			35
Impairment losses on investments	—			—			—			—			—			—			—			—			(495		)	—			(495		)
Other income, net	—			1			2			2			—			5			3			2			21			(17		)	19
Loss on debt extinguishment	—			—			—			—			—			—			—			—			(175		)	—			(175		)
Interest (expense)/income	(4		)	16			(47		)	(41		)	(2		)	(6		)	(7		)	(19		)	(571		)	16			(665		)
Income/(loss) before income taxes	366			316			(98		)	(14		)	54			13			(63		)	24			(1,251		)	7			(646		)
Income tax (benefit)/expense	(3		)	—			—			—			—			—			—			9			(847		)	(2		)	(843		)
Net income/(loss)	369			316			(98		)	(14		)	54			13			(63		)	15			(404		)	9			197
(f) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	5		$	1,586		$	43		$	—		$	—		$	25		$	23		$	—		$	—
(g) Includes Green Mountain Energy results and Energy Plus results for the period October 1, 2011 to December 31, 2011.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Reconciliation of NRG's basic and diluted earnings per share	'
	The reconciliation of NRG's basic (loss)/earnings per share to diluted (loss)/earnings per share is shown in the following table:
		Year Ended December 31,
		2013				2012			2011
		(In millions, except per share amounts)
	Basic (loss)/earnings per share attributable to NRG common stockholders
	Net (loss)/income attributable to NRG Energy, Inc.	$	(386	)		$	295		$	197
	Dividends for preferred shares	9				9			9
	(Loss)/Income Available to Common Stockholders	$	(395	)		$	286		$	188
	Weighted average number of common shares outstanding	323				232			240
	(Loss)/Earnings per weighted average common share — basic	$	(1.22	)		$	1.23		$	0.78
	Diluted (loss)/earnings per share attributable to NRG common stockholders
	Weighted average number of common shares outstanding	323				232			240
	Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—				2			1
	Total dilutive shares	323				234			241
	(Loss)/Earnings per weighted average common share — diluted	$	(1.22	)		$	1.22		$	0.78
Summary of NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings per share	'
	The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted (loss)/earnings per share:
		Year Ended December 31,
		2013			2012			2011
		(In millions of shares)
	Equity compensation	9			8			7
	Embedded derivative of 3.625% redeemable perpetual preferred stock	16			16			16
	Total	25			24			23

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income tax provision from continuing operations	'
	The income tax provision from continuing operations consisted of the following amounts:
		Year Ended December 31,
		2013			2012			2011
		(In millions, except percentages)
	Current
	U.S. Federal	$	—		$	—		$	(538	)
	State	11			20			10
	Foreign	—			13			16
	Total — current	11			33			(512		)
	Deferred
	U.S. Federal	(207		)	(326		)	(317		)
	State	(57		)	(24		)	(5		)
	Foreign	(29		)	(10		)	(9		)
	Total — deferred	(293		)	(360		)	(331		)
	Total income tax benefit	$	(282	)	$	(327	)	$	(843	)
	Effective tax rate	44.5		%	2,725.00		%	130.5		%
Domestic and foreign components of income/(loss) before income tax (benefit)/expense	'
	The following represents the domestic and foreign components of loss before income tax benefit:
		Year Ended December 31,
		2013			2012			2011
		(In millions)
	U.S.	$	(549	)	$	(41	)	$	(680	)
	Foreign	(85		)	29			34
	Total	$	(634	)	$	(12	)	$	(646	)
Reconciliation of the U.S. federal statutory rate to NRG's effective rate	'
	A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate is as follows:
		Year Ended December 31,
		2013			2012			2011
		(In millions, except percentages)
	Loss Before Income Taxes	$	(634	)	$	(12	)	$	(646	)
	Tax at 35%	(222		)	(4		)	(226		)
	State taxes, including change in rate, net of federal benefit	11			1			15
	Foreign operations	5			(24		)	(3		)
	Federal and state tax credits	(36		)	(158		)	(1		)
	Valuation allowance	(5		)	5			(63		)
	Expiration/utilization of capital losses	10			—			45
	Reversal of valuation allowance on expired/utilized capital losses	(10		)	—			(45		)
	Impact of non-taxable equity earnings	(14		)	(7		)	—
	Bargain purchase gain related to GenOn acquisition	—			(104		)	—
	Foreign earnings	—			—			4
	Interest accrued on uncertain tax positions	(3		)	2			2
	Production tax credit	(14		)	(14		)	(14		)
	Reversal of uncertain tax position reserves	(11		)	(13		)	(561		)
	Tax expense attributable to consolidated partnerships	8			—			—
	Other	(1		)	(11		)	4
	Income tax benefit	$	(282	)	$	(327	)	$	(843	)
	Effective income tax rate	44.5		%	2,725.00		%	130.5		%
Company's deferred tax assets and liabilities	'
	The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:
		As of December 31,
		2013			2012
		(In millions)
	Deferred tax liabilities:
	Emissions allowances	$	15		$	15
	Difference between book and tax basis of property	22			123
	Derivatives, net	334			323
	Goodwill	191			165
	Cumulative translation adjustments	9			19
	Intangibles amortization (excluding goodwill)	—			85
	Investment in projects	540			52
	Other	—			—
	Total deferred tax liabilities	1,111			782
	Deferred tax assets:
	Deferred compensation, pension, accrued vacation and other reserves	203			232
	Discount/premium on notes	111			156
	Differences between book and tax basis of contracts	285			343
	Pension and other postretirement benefits	168			274
	Equity compensation	57			57
	Bad debt reserve	18			14
	U.S. capital loss carryforwards	1			1
	U.S. Federal net operating loss carryforwards	1,381			605
	Foreign net operating loss carryforwards	77			89
	State net operating loss carryforwards	161			89
	Foreign capital loss carryforwards	1			1
	Deferred financing costs	3			33
	Federal and state tax credits	308			258
	Federal benefit on state uncertain tax positions	23			18
	Intangibles amortization (excluding goodwill)	20			—
	Other	23			7
	Total deferred tax assets	2,840			2,177
	Valuation allowance	(291		)	(191		)
	Total deferred tax assets, net of valuation allowance	2,549			1,986
	Net deferred tax asset	$	1,438		$	1,204
Summary of NRG's net deferred tax position	'
	The following table summarizes NRG's net deferred tax position:
		As of December 31,
		2013			2012
		(In millions)
	Net deferred tax asset — current	$	258		$	56
	Net deferred tax asset — noncurrent	1,202			1,203
	Net deferred tax liability — noncurrent	$	(22	)	$	(55	)
	Net deferred tax asset	$	1,438		$	1,204
Reconciliation of total amounts of uncertain tax benefits	'
	The following table reconciles the total amounts of uncertain tax benefits:
		As of December 31,
		2013			2012
		(In millions)
	Balance as of January 1	$	193		$	178
	Increase due to current year positions	2			21
	Decrease due to current year positions	—			(3		)
	Increase due to prior year positions	4			13
	Decrease due to prior year positions	(40		)	(21		)
	Increase due to acquisitions	—			5
	Decrease due to settlements and payments	(44		)	—
	Uncertain tax benefits as of December 31	$	115		$	193

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation [Abstract]	'
Summary of Company's NQSO activity, and changes during the year	'
	The following table summarizes the Company's NQSO activity and changes during the year:
		Shares			Weighted Average			Weighted Average Remaining Contractual Term (In years)		Aggregate Intrinsic Value
					Exercise Price					(In millions)
		(In whole)
	Outstanding at December 31, 2012	6,677,885			$	28.85		4		$	17
	Forfeited	(1,044,902	)		27.75
	Exercised	(1,656,002	)		14.28
	Outstanding at December 31, 2013	3,976,981			35.2			2		17
	Exercisable at December 31, 2013	3,592,810			31.8			2		13
Summary of weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from the exercises of options	'
	The following table summarizes the weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from the exercises of options:
		Year Ended December 31,
		2013				2012			2011
		(In millions, except for weighted average)
	Weighted average grant date fair value per option granted	$	—			$	—		$	8.73
	Total intrinsic value of options exercised	19				0.3			0.2
	Cash received from options exercised	33				1			2
Summary of Company's non-vested RSU awards and changes during the year	'
	The following table summarizes the Company's non-vested RSU awards and changes during the year:
		Units			Weighted Average Grant-Date Fair Value per Unit
		(In whole)
	Non-vested at December 31, 2012	2,608,551			$	21.28
	Granted	617,009			23.37
	Forfeited	(322,448	)		21.34
	Vested	(879,933	)		22.64
	Non-vested at December 31, 2013	2,023,179			21.22
Summary of Company's outstanding DSU awards and changes during the year	'
	The following table summarizes the Company's outstanding DSU awards and changes during the year:
		Units			Weighted Average Grant-Date Fair Value per Unit
		(In whole)
	Outstanding at December 31, 2012	697,515			$	20.91
	Granted	205,667			23.18
	Conversions (a)	(524,636	)		22.55
	Outstanding at December 31, 2013	378,546			19.78
Summary of Company's non-vested MSU awards and changes during the year	'
	The following table summarizes the Company's non-vested MSU awards and changes during the year:
		Units			Weighted Average Grant-Date Fair Value per Unit
		(in whole)
	Non-vested at December 31, 2012	1,003,920			$	22.43
	Granted	1,066,626			27.46
	Vested	(20,000	)		26.64
	Forfeited	(214,040	)		24.16
	Non-vested at December 31, 2013	1,836,506			24.72
Summary of significant assumptions used in the fair value model with respect to the Company's MSUs	'
	Significant assumptions used in the fair value model with respect to the Company's MSUs are summarized below:
		2013			2012
	Expected volatility	27.12%-29.11%			29.60%-35.98%
	Expected term (in years)	3			3
	Risk free rate	0.37%-0.59%			0.29%-0.40%
Summary of Company's non-vested PU awards and changes during the year	'
	The following table summarizes the Company's non-vested PU awards and changes during the year:
		Outstanding			Weighted Average Grant-Date Fair Value per Unit
		Units
		(In whole)
	Non-vested at December 31, 2012	647,200			$	21.88
	Vested	(36,700	)		19.89
	Forfeited	(296,200	)		23.28
	Non-vested at December 31, 2013	314,300			20.8
Summary of significant assumptions used in the fair value model with respect to the Company's PUs	'
Summary of NRG's total compensation expense recognized and total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized	'
												Non-vested Compensation Cost
		Compensation Expense										Unrecognized		Weighted Average Recognition Period Remaining (In years)
												Total Cost
		Year Ended December 31										As of December 31
	Award	2013				2012			2011			2013		2013
		(In millions, except weighted average data)
	NQSOs	$	4			$	6		$	8		$	1	1.1
	RSUs	18				21			12			18		1.4
	DSUs	2				2			2			—		0
	MSUs	14				7			—			28		1.7
	PUs	2				4			5			—		0
	Total	$	40			$	40		$	27		$	47
	Tax detriment recognized	$	(12	)		$	8		$	1

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Summary of NRG's material related-party transactions with affiliates	'
	The following table summarizes NRG's material related party transactions with affiliates that are included in the Company's operating revenues, operating costs and other income and expense:
		Year Ended December 31,
		2013		2012		2011
		(In millions)
	Revenues from Related Parties Included in Operating Revenues
	Gladstone	$	6	$	7	$	7
	GenConn (a)	5		6		3
	Total	$	11	$	13	$	10
	Interest income from Related Parties Included in Other Income and Expense
	GenConn (a)	$	—	$	—	$	1
	Kraftwerke Schkopau GBR (b)	—		2		4
	Total	$	—	$	2	$	5
	(a)	The period in 2011 is from January 1, 2011 to June 30, 2011.
	(b)	The period in 2012 is from January 1, 2012 to July 17, 2012.

Commitments_and_Contingencies_1

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Future minimum lease commitments under operating leases	'
	Future minimum lease commitments under the GenOn Mid-Atlantic operating leases for the years ending after December 31, 2013, are as follows:
	Period	(In millions)
	2014	$	131
	2015	110
	2016	150
	2017	144
	2018	105
	Thereafter	686
	Total	$	1,326
	Future minimum lease commitments under the REMA operating leases for the years ending after December 31, 2013, are as follows:
	Period	(In millions)
	2014	$	63
	2015	56
	2016	61
	2017	63
	2018	55
	Thereafter	400
	Total	$	698
	Future minimum lease commitments under operating leases for the years ending after December 31, 2013, are as follows:
	Period	(In millions)
	2014	$	79
	2015	78
	2016	63
	2017	41
	2018	38
	Thereafter	138
	Total (a)	$	437
Commitments under coal, gas and transportation contractual agreements	'
	As of December 31, 2013, the Company's commitments under such outstanding agreements are estimated as follows:
	Period	(In millions)
	2014	$	963
	2015	272
	2016	254
	2017	220
	2018	136
	Thereafter	719
	Total	$	2,564
Minimum purchase commitment obligations under purchased power agreements	'
	Minimum purchase commitment obligations are as follows as of December 31, 2013:
	Period	(In millions)
	2014	$	24
	2015	18
	2016	12
	2017	10
	2018	1
	Thereafter	—
	Total (a)	$	65
	(a)	As of December 31, 2013, the maximum remaining term under any individual purchased power contract is five years.

Cash_Flow_Information_Tables

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Details of supplemental disclosures of cash flow and non-cash investing and financing information	'
	Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
		Year Ended December 31,
		2013			2012			2011
		(In millions)
	Interest paid, net of amount capitalized	$	836		$	579		$	642
	Income taxes (refunded)/paid (a)	(60		)	17			26
	Non-cash investing and financing activities:
	Additions to fixed assets for accrued capital expenditures	405			563			292
	Decrease to fixed assets for accrued grants and related tax impact	(681		)	(87		)	(32		)
	Decrease to notes receivable for equity conversion	—			—			63
	Issuance of shares for GenOn acquisition	—			(2,188		)	—
	(a) In 2013, the net income taxes refunded are net of $28 million income taxes paid and $87 million income tax refunds. No tax refunds were received in 2012. In 2011, income taxes paid are net of $8 million of income tax refunds received.

Guarantees_Guarantees_Tables

Guarantees Guarantees (Tables)	12 Months Ended
	Dec. 31, 2013
Guarantees [Abstract]	'
Summary of NRG's estimated guarantees, indemnity, and other contingent liability	'
	The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity:
		By Remaining Maturity at December 31,
		2013
	Guarantees	Under		1-3 Years		3-5 Years		Over		Total		2012
		1 Year						5 Years				Total
		(In millions)
	Letters of credit and surety bonds	$	1,654	$	47	$	—	$	—	$	1,701	$	1,594
	Asset sales guarantee obligations	—		—		275		—		275		275
	Commercial sales arrangements	81		112		23		1,338		1,554		1,579
	Other guarantees	78		4		—		469		551		356
	Total guarantees	$	1,813	$	163	$	298	$	1,807	$	4,081	$	3,804

Jointly_Owned_Plants_Tables

Jointly Owned Plants (Tables)	12 Months Ended
	Dec. 31, 2013
Jointly Owned Plants Disclosure [Abstract]	'
Summary of NRG's proportionate ownership interest in the company's jointly-owned facilities	'
	The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities:
	As of December 31, 2013	Ownership		Property, Plant &		Accumulated			Construction in
		Interest		Equipment		Depreciation			Progress
		(In millions unless otherwise stated)
	South Texas Project Units 1 and 2, Bay City, TX	44	%	$	2,679	$	(1,293	)	$	19
	Big Cajun II Unit 3, New Roads, LA	58	%	178		(95		)	18
	Cedar Bayou Unit 4, Baytown, TX	50	%	215		(49		)	—
	Keystone, Shelocta, PA	3.7	%	92		(35		)	1
	Conemaugh, New Florence, PA	3.72	%	82		(38		)	14

Unaudited_Quarterly_Financial_1

Unaudited Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Summary of Unaudited Quarterly Financial Data	'
	Summarized unaudited quarterly financial data is as follows:
		Quarter Ended
		2013
		December 31			September 30			June 30		March 31
		(In millions, except per share data)
	Operating revenues	$	2,795		$	3,490		$	2,930	$	2,081
	Operating (loss)/income	(205		)	527			287		(266		)
	Net (loss)/income	(283		)	$	135		130		(334		)
	Net (loss)/income attributable to NRG Energy, Inc.	$	(290	)	$	116		$	122	$	(334	)
	Weighted average number of common shares outstanding — basic	323			323			323		323
	Net (loss)/income per weighted average common share — basic	$	(0.90	)	$	0.36		$	0.38	$	(1.03	)
	Weighted average number of common shares outstanding — diluted	323			327			327		323
	Net (loss)/income per weighted average common share — diluted	$	(0.90	)	$	0.35		$	0.37	$	(1.03	)
		Quarter Ended
		2012
		December 31			September 30			June 30		March 31
		(In millions, except per share data)
	Operating revenues	$	2,063		$	2,331		$	2,166	$	1,862
	Operating income/(loss)	37			86			397		(170		)
	Net income/(loss)	254			8			259		(206		)
	Net income/(loss) attributable to NRG Energy, Inc.	$	252		$	(1	)	$	251	$	(207	)
	Weighted average number of common shares outstanding — basic	247			228			228		228
	Net income/(loss) per weighted average common share — basic	$	1.02		$	(0.01	)	$	1.09	$	(0.92	)
	Weighted average number of common shares outstanding — diluted	249			228			229		228
	Net income/(loss) per weighted average common share — diluted	$	1.01		$	(0.01	)	$	1.08	$	(0.92	)

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Schedule of Guarantor Subsidiaries	'
	Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2013:
	Ace Energy, Inc.	Middletown Power LLC	NRG Oswego Harbor Power Operations Inc.
	Allied Warranty LLC	Montville Power LLC	NRG PacGen Inc.
	Allied Home Warranty GP LLC	NEO Corporation	NRG Power Marketing LLC
	Arthur Kill Power LLC	NEO Freehold-Gen LLC	NRG Reliability Solutions LLC
	Astoria Gas Turbine Power LLC	NEO Power Services Inc.	NRG Renter's Protection LLC
	BidURenergy, Inc.	New Genco GP, LLC	NRG Retail LLC
	Cabrillo Power I LLC	Norwalk Power LLC	NRG Retail Northeast LLC
	Cabrillo Power II LLC	NRG Affiliate Services Inc.	NRG Rockford Acquisition LLC
	Carbon Management Solutions LLC	NRG Artesian Energy LLC	NRG Saguaro Operations Inc.
	Clean Edge Energy LLC	NRG Arthur Kill Operations Inc.	NRG Security LLC
	Conemaugh Power LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Services Corporation
	Connecticut Jet Power LLC	NRG Bayou Cove LLC	NRG SimplySmart Solutions LLC
	Cottonwood Development LLC	NRG Cabrillo Power Operations Inc.	NRG South Central Affiliate Services Inc.
	Cottonwood Energy Company LP	NRG California Peaker Operations LLC	NRG South Central Generating LLC
	Cottonwood Generating Partners I LLC	NRG Cedar Bayou Development Company, LLC	NRG South Central Operations Inc.
	Cottonwood Generating Partners II LLC	NRG Connecticut Affiliate Services Inc.	NRG South Texas LP
	Cottonwood Generating Partners III LLC	NRG Construction LLC	NRG Texas C&I Supply LLC
	Cottonwood Technology Partners LP	NRG Curtailment Solutions LLC	NRG Texas Gregory LLC
	Devon Power LLC	NRG Development Company Inc.	NRG Texas Holding Inc.
	Dunkirk Power LLC	NRG Devon Operations Inc.	NRG Texas LLC
	Eastern Sierra Energy Company LLC	NRG Dispatch Services LLC	NRG Texas Power LLC
	El Segundo Power, LLC	NRG Dunkirk Operations Inc.	NRG Unemployment Protection LLC
	El Segundo Power II LLC	NRG El Segundo Operations Inc.	NRG Warranty Services LLC
	Elbow Creek Wind Project LLC	NRG Energy Labor Services LLC	NRG West Coast LLC
	Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Western Affiliate Services Inc.
	Energy Curtailment Specialists, Inc.	NRG Energy Services International Inc.	O'Brien Cogeneration, Inc. II
	Energy Plus Holdings LLC	NRG Energy Services LLC	ONSITE Energy, Inc.
	Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	Oswego Harbor Power LLC
	Energy Protection Insurance Company	NRG Home & Business Solutions LLC	RE Retail Receivables, LLC
	Everything Energy LLC	NRG Home Solutions LLC	Reliant Energy Northeast LLC
	GCP Funding Company, LLC	NRG Home Solutions Product LLC	Reliant Energy Power Supply, LLC
	Green Mountain Energy Company	NRG Homer City Services LLC	Reliant Energy Retail Holdings, LLC
	Green Mountain Energy Company	NRG Huntley Operations Inc.	Reliant Energy Retail Services, LLC
	(NY Com) LLC	NRG Identity Protect LLC	RERH Holdings LLC
	Green Mountain Energy Company	NRG Ilion Limited Partnership	Saguaro Power LLC
	(NY Res) LLC	NRG Ilion LP LLC	Somerset Operations Inc.
	Gregory Partners, LLC	NRG International LLC	Somerset Power LLC
	Gregory Power Partners LLC	NRG Maintenance Services LLC	Texas Genco Financing Corp.
	Huntley Power LLC	NRG Mextrans Inc.	Texas Genco GP, LLC
	Independence Energy Alliance LLC	NRG MidAtlantic Affiliate Services Inc.	Texas Genco Holdings, Inc.
	Independence Energy Group LLC	NRG Middletown Operations Inc.	Texas Genco LP, LLC
	Independence Energy Natural Gas LLC	NRG Montville Operations Inc.	Texas Genco Operating Services, LLC
	Indian River Operations Inc.	NRG New Jersey Energy Sales LLC	Texas Genco Services, LP
	Indian River Power LLC	NRG New Roads Holdings LLC	US Retailers LLC
	Keystone Power LLC	NRG North Central Operations Inc.	Vienna Operations Inc.
	Langford Wind Power, LLC	NRG Northeast Affiliate Services Inc.	Vienna Power LLC
	Lone Star A/C & Appliance Repairs, LLC	NRG Norwalk Harbor Operations Inc.	WCP (Generation) Holdings LLC
	Louisiana Generating LLC	NRG Operating Services, Inc.	West Coast Power LLC
	Meriden Gas Turbines LLC
Condensed Consolidating Statement of Operations	'
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	For the Year Ended December 31, 2013
		Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
		Subsidiaries			Subsidiaries			(Note Issuer)						Balance
		(In millions)
	Operating Revenues
	Total operating revenues	$	8,223		$	3,211		$	—		$	(139	)	$	11,295
	Operating Costs and Expenses
	Cost of operations	6,150			2,104			—			(133		)	8,121
	Depreciation and amortization	837			407			12						1,256
	Impairment losses	459			—			—			—			459
	Selling, general and administrative	446			230			234			(6		)	904
	Acquisition-related transaction and integration costs	—			70			58			—			128
	Development activity expenses	—			34			50			—			84
	Total operating costs and expenses	7,892			2,845			354			(139		)	10,952
	Operating Income/(Loss)	331			366			(354		)	—			343
	Other Income/(Expense)
	Equity in earnings/(losses) of consolidated subsidiaries	(67		)	(14		)	221			(140		)	—
	Equity in earnings/(losses) of unconsolidated affiliates	(11		)	22			—			(4		)	7
	Impairment charge on investment	—			(99		)				—			(99		)
	Other income, net	6			11			(2		)	(2		)	13
	Loss on debt extinguishment				(12		)	(38		)	—			(50		)
	Interest expense	(24		)	(318		)	(506		)	—			(848		)
	Total other income/(expense)	(96		)	(410		)	(325		)	(146		)	(977		)
	Income/(Loss) Before Income Taxes	235			(44		)	(679		)	(146		)	(634		)
	Income tax expense/(benefit)	114			(89		)	(307		)	—			(282		)
	Net Income	121			45			(372		)	(146		)	(352		)
	Less: Net income attributable to noncontrolling interest	—			27			13			(6		)	34
	Net Income attributable to NRG Energy, Inc	$	121		$	18		$	(385	)	$	(140	)	$	(386	)
	(a)	All significant intercompany transactions have been eliminated in consolidation.
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	For the Year Ended December 31, 2012
		Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
		Subsidiaries			Subsidiaries			(Note Issuer)						Balance
		(In millions)
	Operating Revenues
	Total operating revenues	$	7,998		$	509		$	—		$	(85	)	$	8,422
	Operating Costs and Expenses
	Cost of operations	5,916			300			—			(76		)	6,140
	Depreciation and amortization	860			79			11			—			950
	Selling, general and administrative	466			45			307			(11		)	807
	Acquisition-related transactions and integration costs	—			53			54			—			107
	Development activity expense	—			32			36			—			68
	Total operating costs and expenses	7,242			509			408			(87		)	8,072
	Operating Income/(Loss)	756			—			(408		)	2			350
	Other (Expense)/Income
	Equity in earnings/(losses) of consolidated subsidiaries	30			(15		)	620			(635		)	—
	Equity in earnings/(losses) of unconsolidated affiliates	8			31			(2		)	—			37
	Bargain purchase gain related to GenOn acquisition	—			—			296			—			296
	Impairment charge on investment	(2		)	—			—			—			(2		)
	Other income, net	6			6			9			(2		)	19
	Loss on debt extinguishment	—			—			(51		)	—			(51		)
	Interest expense	(26		)	(90		)	(545		)	—			(661		)
	Total other income/(expense)	16			(68		)	327			(637		)	(362		)
	Income/(Loss) Before Income Taxes	772			(68		)	(81		)	(635		)	(12		)
	Income tax expense/(benefit)	237			(188		)	(376		)	—			(327		)
	Net Income	$	535		$	120		$	295		$	(635	)	$	315
	Less: Net income attributable to noncontrolling interest	—			20			—			—			20
	Net Income attributable to NRG Energy, Inc	$	535		$	100		$	295		$	(635	)	$	295
	(a)	All significant intercompany transactions have been eliminated in consolidation.
		Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
Subsidiaries			Subsidiaries			Balance
	(In millions)
Operating Revenues
Total operating revenues	$	8,730		$	381		$	—		$	(32	)	$	9,079
Operating Costs and Expenses
Cost of operations	6,489			277			—			(21		)	6,745
Depreciation and amortization	843			40			13			—			896
Impairment losses	160			—			—			—			160
Selling, general and administrative	334			4			252			(4		)	586
Development activity expenses	—			11			46			—			57
Total operating costs and expenses	7,826			332			311			(25		)	8,444
Operating Income/(Loss)	904			49			(311		)	(7		)	635
Other Income
Equity in earnings/(losses) of consolidated subsidiaries	24			(7		)	593			(610		)	—
Equity in earnings of unconsolidated affiliates	10			25			—			—			35
Impairment charge on investment	(495		)	—			—			—			(495		)
Other income, net	2			13			4			—			19
Loss on debt extinguishment	—			—			(175		)	—			(175		)
Interest expense	(59		)	(56		)	(550		)	—			(665		)
Total other expense	(518		)	(25		)	(128		)	(610		)	(1,281		)
Income/(Loss) Before Income Taxes	386			24			(439		)	(617		)	(646		)
Income tax (benefit)/expense	(214		)	7			(636		)	—			(843		)
Net Income attributable to NRG Energy, Inc	$	600		$	17		$	197		$	(617	)	$	197
(a)	All significant intercompany transactions have been eliminated in consolidation.
Condensed Consolidating Statements of Comprehensive Income	'
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
	For the Year Ended December 31, 2013
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc.			Eliminations(a)			Consolidated Balance
								(Note Issuer)
		(In millions)
	Net Income	$	121		$	45		$	(372	)	$	(146	)	$	(352	)
	Other comprehensive (loss)/income, net of tax
	Unrealized loss on derivatives, net	(71		)	50			120			(91		)	8
	Foreign currency translation adjustments, net	—			(20		)	(4		)	—			(24		)
	Available-for-sale securities, net	—			—			3			—			3
	Defined benefit plan, net	75			63			30			—			168
	Other comprehensive loss	4			93			149			(91		)	155
	Comprehensive income	125			138			(223		)	(237		)	(197		)
	Less: Comprehensive income attributable to noncontrolling interest	—			27			13			(6		)	34
	Comprehensive income attributable to NRG Energy, Inc.	125			111			(236		)	(231		)	(231		)
	Dividends for preferred shares	—			—			9			—			9
	Comprehensive income available for common stockholders	$	125		$	111		$	(245	)	$	(231	)	$	(240	)
	(a)	All significant intercompany transactions have been eliminated in consolidation.
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
	For the Year Ended December 31, 2012
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc.			Eliminations(a)			Consolidated Balance
								(Note Issuer)
		(In millions)
	Net Income	$	535		$	120		$	295		$	(635	)	$	315
	Other comprehensive income/(loss), net of tax
	Unrealized loss on derivatives, net	(160		)	(30		)	(214		)	241			(163		)
	Foreign currency translation adjustments, net	—			(2		)	1			—			(1		)
	Reclassification adjustment for translation loss realized upon sale of Schkopau, net	—			(11		)	—			—			(11		)
	Available-for-sale securities, net	—			—			3			—			3
	Defined benefit plan, net	(38		)	—			(14		)	—			(52		)
	Other comprehensive loss	(198		)	(43		)	(224		)	241			(224		)
	Comprehensive income	337			77			71			(394		)	91
	Less: Comprehensive income attributable to noncontrolling interest	—			20			—			—			20
	Comprehensive income attributable to NRG Energy, Inc.	337			57			71			(394		)	71
	Dividends for preferred shares	—			—			9			—			9
	Comprehensive income available for common stockholders	$	337		$	57		$	62		$	(394	)	$	62
	(a)	All significant intercompany transactions have been eliminated in consolidation.
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
	For the Year Ended December 31, 2011
		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc.			Eliminations(a)			Consolidated Balance
								(Note Issuer)
		(In millions)
	Net Income	$	600		$	17		$	197		$	(617	)	$	197
	Other comprehensive income/(loss), net of tax
	Unrealized loss on derivatives, net	(303		)	(27		)	(345		)	366			(309		)
	Foreign currency translation adjustments, net	—			(2		)	—			—			(2		)
	Available-for-sale securities, net	—			—			(1		)	—			(1		)
	Defined benefit plan, net	(34		)	—			(12		)	—			(46		)
	Other comprehensive loss	(337		)	(29		)	(358		)	366			(358		)
	Comprehensive income/(loss) attributable to NRG Energy, Inc.	263			(12		)	(161		)	(251		)	(161		)
	Dividends for preferred shares	—			—			9			—			9
	Comprehensive income/(loss) available for common stockholders	$	263		$	(12	)	$	(170	)	$	(251	)	$	(170	)
	(a)	All significant intercompany transactions have been eliminated in consolidation.
Condensed Consolidating Balance Sheets	'
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	December 31, 2013
		Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated Balance
		Subsidiaries			Subsidiaries
		(In millions)
	ASSETS
	Current Assets
	Cash and cash equivalents	$	56		$	870		$	1,328		$	—		$	2,254
	Funds deposited by counterparties	7			56			—			—			63
	Restricted cash	12			252			4			—			268
	Accounts receivable - trade, net	965			249			—			—			1,214
	Inventory	436			462			—			—			898
	Derivative instruments	866			470			—			(8		)	1,328
	Deferred income taxes	—			41			217			—			258
	Cash collateral paid in support of energy risk management activities	214			62			—			—			276
	Renewable energy grant receivable	—			539			—			—			539
	Prepayments and other current assets	4,778			379			(3,802		)	(857		)	498
	Total current assets	7,334			3,380			(2,253		)	(865		)	7,596
	Net Property, Plant and Equipment	9,116			10,604			153			(22		)	19,851
	Other Assets
	Investment in subsidiaries	32			422			18,266			(18,720		)	—
	Equity investments in affiliates	(30		)	583						(100		)	453
	Notes receivable, less current portion	—			62			105			(94		)	73
	Goodwill	1,973			12			—			—			1,985
	Intangible assets, net	925			232			4			(21		)	1,140
	Nuclear decommissioning trust fund	551						—			—			551
	Deferred income taxes	—			681			521			—			1,202
	Derivative instruments	110			202			—			(1		)	311
	Other non-current assets	76			281			383			—			740
	Total other assets	3,637			2,475			19,279			(18,936		)	6,455
	Total Assets	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902
	LIABILITIES AND STOCKHOLDERS' EQUITY
	Current Liabilities
	Current portion of long-term debt and capital leases	$	1		$	1,029		$	20		$	—		$	1,050
	Accounts payable	652			352			34			—			1,038
	Accounts payable - affiliate	1,350			760			(1,253		)	(857		)	—
	Derivative instruments	859			204			—			(8		)	1,055
	Deferred income taxes	—			—			—			—			—
	Cash collateral received in support of energy risk management activities	6			57			—			—			63
	Accrued expenses and other current liabilities	297			410			291			—			998
	Total current liabilities	3,165			2,812			(908		)	(865		)	4,204
	Other Liabilities
	Long-term debt and capital leases	317			7,837			7,707			(94		)	15,767
	Nuclear decommissioning reserve	294			—			—			—			294
	Nuclear decommissioning trust liability	324			—			—			—			324
	Postretirement and other benefit obligations	218			194			94			—			506
	Deferred income taxes	1,024			(1,002		)	—			—			22
	Derivative instruments	147			49			—			(1		)	195
	Out-of-market contracts	127			1,050			—			—			1,177
	Other non-current liabilities	194			421			80			—			695
	Total non-current liabilities	2,645			8,549			7,881			(95		)	18,980
	Total liabilities	5,810			11,361			6,973			(960		)	23,184
	3.625% Preferred Stock							249						249
	Stockholders' Equity	14,277			5,098			9,957			(18,863		)	10,469
	Total Liabilities and Stockholders' Equity	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902
	(a)	All significant intercompany transactions have been eliminated in consolidation.
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING BALANCE SHEETS
	December 31, 2012
		Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
		Subsidiaries			Subsidiaries									Balance
		(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	78		$	1,258		$	751		$	—		$	2,087
Funds deposited by counterparties	131			140			—			—			271
Restricted cash	11			196			10			—			217
Accounts receivable - trade, net	807			254			—			—			1,061
Inventory	472			431			—			—			903
Derivative instruments	2,058			604			—			(18		)	2,644
Deferred income taxes	(153		)	10			199			—			56
Cash collateral paid in support of energy risk management activities	81			148			—			—			229
Renewable energy grant receivable	—			58			—			—			58
Prepayments and other current assets	2,966			(12		)	(2,518		)	10			446
Total current assets	6,451			3,087			(1,558		)	(8		)	7,972
Net Property, Plant and Equipment	9,905			10,147			121			(20		)	20,153
Other Assets
Investment in subsidiaries	244			(102		)	17,565			(17,707		)	—
Equity investments in affiliates	33			633			10			—			676
Notes receivable, less current portion	3			74			531			(529		)	79
Goodwill	1,944			12			—			—			1,956
Intangible assets, net	1,042			187			33			(52		)	1,210
Nuclear decommissioning trust fund	473			—			—			—			473
Deferred income taxes	(915		)	1,886			232			—			1,203
Derivative instruments	149			515			—			(2		)	662
Other non-current assets	85			304			210			—			599
Total other assets	3,058			3,509			18,581			(18,290		)	6,858
Total Assets	$	19,414		$	16,743		$	17,144		$	(18,318	)	$	34,983
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	137		$	15		$	(6	)	$	147
Accounts payable	541			585			46			—			1,172
Accounts payable - affiliate	(55		)	1,421			(1,366		)	—			—
Derivative instruments	1,726			271			2			(18		)	1,981
Cash collateral received in support of energy risk management activities	131			140			—			—			271
Accrued expenses and other current liabilities	354			502			243			—			1,099
Total current liabilities	2,698			3,056			(1,060		)	(24		)	4,670
Other Liabilities
Long-term debt and capital leases	310			8,459			7,496			(529		)	15,736
Nuclear decommissioning reserve	354			—			—			—			354
Nuclear decommissioning trust liability	273			—			—			—			273
Postretirement and other benefit obligations	431			326			46			—			803
Deferred income taxes	—			—			55			—			55
Derivative instruments	312			190			—			(2		)	500
Out-of-market commodity contracts	180			1,129			—			(31		)	1,278
Other non-current liabilities	187			520			89			—			796
Total non-current liabilities	2,047			10,624			7,686			(562		)	19,795
Total liabilities	4,745			13,680			6,626			(586		)	24,465
3.625% Preferred Stock	—			—			249			—			249
Stockholders' Equity	14,669			3,063			10,269			(17,732		)	10,269
Total Liabilities and Stockholders' Equity	$	19,414		$	16,743		$	17,144		$	(18,318	)	$	34,983
(a)	All significant intercompany transactions have been eliminated in consolidation.
Condensed Consolidating Statements of Cash Flows	'
		Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
		Subsidiaries			Subsidiaries									Balance
		(In millions)
	Net Cash Provided/(Used) by Operating Activities	2,318			(217		)	(2,546		)	1,715			1,270
	Cash Flows from Investing Activities
	Intercompany loans to subsidiaries	(1,722		)	7			1,715			—			—
	Acquisition of business, net of cash acquired				(179		)	(315		)	—			(494		)
	Capital expenditures	(528		)	(1,413		)	(46		)	—			(1,987		)
	Increase in restricted cash, net	(1		)	(22		)	1			—			(22		)
	Decrease in restricted cash - U.S. DOE projects				(31		)	5			—			(26		)
	Increase in notes receivable	2			(7		)	(6		)	—			(11		)
	Proceeds from renewable energy grants				55			—			—			55
	Purchases of emission allowances, net of proceeds	5			—			—			—			5
	Investments in nuclear decommissioning trust fund securities	(514		)	—			—			—			(514		)
	Proceeds from sales of nuclear decommissioning trust fund securities	488			—			—			—			488
	Proceeds/(purchases) from sale of assets, net	13			—			—			—			13
	Other	(4		)	(11		)	(20		)	—			(35		)
	Net Cash Used by Investing Activities	(2,261		)	(1,601		)	1,334			—			(2,528		)
	Cash Flows from Financing Activities
	Proceeds/(payments) from intercompany loans	—			—			1,715			(1,715		)	—
	Payment of dividends to preferred stockholders							(154		)	—			(154		)
	Payments of intercompany dividends	—			—			—			—			—
	Payment for treasury stock	—			—			(25		)	—			(25		)
	Payments for settlement of acquired derivatives that include financing elements	(79		)	346			—			—			267
	Proceeds from issuance of long-term debt	—			1,292			485			—			1,777
	Sale proceeds and other contributions from noncontrolling interests in subsidiaries	—			531			—			—			531
	Proceeds from issuance of common stock	—			—			16			—			16
	Payment of debt issuance and hedging costs	—			(21		)	(29		)	—			(50		)
	Payments for short and long-term debt	—			(716		)	(219		)	—			(935		)
	Net Cash (Used)/Provided by Financing Activities	(79		)	1,432			1,789			(1,715		)	1,427
	Effect of exchange rate changes on cash and cash equivalents	—			(2		)	—			—			(2		)
	Net Increase/(decrease) in Cash and Cash Equivalents	(22		)	(388		)	577			—			167
	Cash and Cash Equivalents at Beginning of Period	78			1,258			751			—			2,087
	Cash and Cash Equivalents at End of Period	$	56		$	870		$	1,328		$	—		$	2,254
	(a)	All significant intercompany transactions have been eliminated in consolidation.
	NRG ENERGY, INC. AND SUBSIDIARIES
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	For the Year Ended December 31, 2012
		Guarantor			Non-Guarantor			NRG Energy, Inc.			Eliminations (a)			Consolidated
		Subsidiaries			Subsidiaries									Balance
		(In millions)
	Cash Flows from Operating Activities
	Net Cash Provided/Used by Operating Activities	2,163			66			(902		)	(178		)	1,149
	Cash Flows from Investing Activities
	Intercompany loans to subsidiaries	(1,792		)	792			—			1,000			—
	Acquisition of businesses, net of cash acquired	—			(17		)	(64		)	—			(81		)
	Cash acquired in GenOn acquisition	—			983			—			—			983
	Capital expenditures	(241		)	(3,091		)	(64		)	—			(3,396		)
	Increase in restricted cash, net	(3		)	(63		)	—			—			(66		)
	Decrease in restricted cash - U.S. DOE projects	—			121			43			—			164
	Increase in notes receivable	(1		)	(21		)	(2		)	—			(24		)
	Purchases of emission allowances, net of proceeds	(1		)	—			—			—			(1		)
	Investments in nuclear decommissioning trust fund securities	(436		)	—			—			—			(436		)
	Proceeds from sales of nuclear decommissioning trust fund securities	399			—			—			—			399
	Proceeds from renewable energy grants	3			59			—			—			62
	Proceeds from sale of assets, net	133			—			4			—			137
	Equity investment in unconsolidated affiliate	(1		)	(12		)	(12		)	—			(25		)
	Other	24			—			(2		)	—			22
	Net Cash Used by Investing Activities	(1,916		)	(1,249		)	(97		)	1,000			(2,262		)
	Cash Flows from Financing Activities
	Proceeds from intercompany loans	—			—			1,000			(1,000		)	—
	Payment of dividends to preferred stockholders	—			—			(50		)	—			(50		)
	Payment of intercompany dividends	(172		)	(6		)	—			178			—
Net (payments of)/receipts from acquired derivatives that include financing elements	(83		)	15			—			—			(68		)
Proceeds from issuance of long-term debt	42			2,105			1,018			—			3,165
Cash proceeds from sale of noncontrolling interest in subsidiary	—			347			—			—			347
Payment of debt issuance and hedging costs	—			(19		)	(16		)	—			(35		)
Payments of short and long-term debt	—			(82		)	(1,178		)	—			(1,260		)
Net Cash (Used)/Provided by Financing Activities	(213		)	2,360			774			(822		)	2,099
Effect of exchange rate changes on cash and cash equivalents	—			(4		)	—			—			(4		)
Net Increase/(Decrease) in Cash and Cash Equivalents	34			1,173			(225		)	—			982
Cash and Cash Equivalents at Beginning of Period	44			85			976			—			1,105
Cash and Cash Equivalents at End of Period	$	78		$	1,258		$	751		$	—		$	2,087
(a)	All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2011
	Guarantor			Non-Guarantor			NRG Energy, Inc.			Elimin-ations (a)			Consolidated
	Subsidiaries			Subsidiaries									Balance
	(In millions)
Cash Flows from Operating Activities
Net Cash Provided by Operating Activities	621			294			1,620			(1,369		)	1,166
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	796			—			287			(1,083		)	—
Investment in subsidiaries	—			(1,300		)	—			1,300			—
Capital expenditures	(383		)	(1,882		)	(45		)	—			(2,310		)
Acquisition of business, net of cash acquired	—			(115		)	(262		)	—			(377		)
Increase in restricted cash	(5		)	(29		)	(1		)	—			(35		)
Increase in restricted cash to support equity requirements for U.S. DOE funded projects	—			(162		)	(53		)	—			(215		)
Decrease in notes receivable	—			12			—			—			12
Purchases of emission allowances, net of proceeds	(19		)	—			—			—			(19		)
Investments in nuclear decommissioning trust fund securities	(406		)	—			—			—			(406		)
Proceeds from sales of nuclear decommissioning trust fund securities	385			—			—			—			385
Proceeds from sale of assets, net	13			(6		)	—			—			7
Equity investment in unconsolidated affiliates, net	(2		)	(64		)	—			—			(66		)
Other	(2		)	(8		)	(13		)	—			(23		)
Net Cash Provided/(Used) by Investing Activities	377			(3,554		)	(87		)	217			(3,047		)
Cash Flows from Financing Activities
(Payments of)/proceeds from intercompany loans	(1,112		)	825			(796		)	1,083			—
Payment of intercompany dividends	(65		)	(4		)	—			69			—
Payment for dividends to preferred stockholders	—			—			(9		)	—			(9		)
Payments for acquired derivatives including financing elements	(83		)	—			—			—			(83		)
Payment for treasury stock	—			—			(430		)	—			(430		)
Installment proceeds from sale of noncontrolling interest of subsidiary	—			29			—			—			29
Proceeds from issuance of common stock	—			—			2			—			2
Proceeds from issuance of long-term debt	138			1,290			4,796			—			6,224
Proceeds from issuance of term loan for funded letter of credit facility	—			1,300			—			—			1,300
Increase in restricted cash supporting funded letter of credit facility	—			—			(1,300		)	—			(1,300		)
Payment of debt issuance and hedging costs	—			(92		)	(115		)	—			(207		)
Payments of short and long-term debt	—			(116		)	(5,377		)	—			(5,493		)
Net Cash (Used)/Provided by Financing Activities	(1,122		)	3,232			(3,229		)	1,152			33
Effect of exchange rate changes on cash and cash equivalents	—			2			—			—			2
Net Decrease in Cash and Cash Equivalents	(124		)	(26		)	(1,696		)	—			(1,846		)
Cash and Cash Equivalents at Beginning of Period	168			111			2,672			—			2,951
Cash and Cash Equivalents at End of Period	$	44		$	85		$	976		$	—		$	1,105
(a)	All significant intercompany transactions have been eliminated in consolidation.

VALUATION_AND_QUALIFYING_ACCOU

VALUATION AND QUALIFYING ACCOUNTS (Tables)	12 Months Ended
	Dec. 31, 2013
Valuation and Qualifying Accounts [Abstract]	'
Schedule of Valuation and Qualifying Accounts Disclosure	'
	SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
	For the Years Ended December 31, 2013, 2012, and 2011
		Balance at		Charged to			Charged to			Deductions				Balance at
		Beginning of		Costs and			Other Accounts							End of Period
		Period		Expenses
		(In millions)
	Allowance for doubtful accounts, deducted from accounts receivable
	Year Ended December 31, 2013	$	32	$	66		$	—		$	(58	)	(a)	40
	Year Ended December 31, 2012	23		46			—			(37		)	(a)	32
	Year Ended December 31, 2011	25		60			—			(62		)	(a)	23
	Income tax valuation allowance, deducted from deferred tax assets
	Year Ended December 31, 2013	$	191	$	32		$	68		$	—			291
	Year Ended December 31, 2012	83		5			103			—				191
	Year Ended December 31, 2011	191		(63		)	(45		)	—				83
	(a)	Represents principally net amounts charged as uncollectible.

Nature_of_Business_Details

Nature of Business (Details)	12 Months Ended
	Dec. 31, 2013
	customer
	MW
Power Generation Facilities	'
Generation capacity (in MW)	45,881
Steam and chilled water capacity (in MWt)	1,374
Number of residential, small business, commercial and industrial customers (in millions)	2,300,000
Domestic Destination [Member]	'
Power Generation Facilities	'
Generation capacity (in MW)	45,276
International [Member]	'
Power Generation Facilities	'
Generation capacity (in MW)	605
NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	948
Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	889
West	'
Power Generation Facilities	'
Generation capacity (in MW)	6,779
South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	5,313
Active	'
Power Generation Facilities	'
Generation capacity (in MW)	46,711
Power Generation Capacity, Megawatts attributed to noncontrolling interest	-830
Active | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	11,286
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0
Active | East	'
Power Generation Facilities	'
Generation capacity (in MW)	20,061
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0
Active | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	5,313
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0
Active | West	'
Power Generation Facilities	'
Generation capacity (in MW)	6,779
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0
Active | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	1,220
Power Generation Capacity, Megawatts attributed to noncontrolling interest	-331
Active | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	1,447
Power Generation Capacity, Megawatts attributed to noncontrolling interest	-499
Active | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	46,106
Power Generation Capacity, Megawatts attributed to noncontrolling interest	-830
Active | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	605
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0
TEXAS	'
Power Generation Facilities	'
Generation capacity (in MW)	11,286
East	'
Power Generation Facilities	'
Generation capacity (in MW)	20,061
Under Construction	'
Power Generation Facilities	'
Generation capacity (in MW)	32
Under Construction | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Under Construction | East	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Under Construction | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Under Construction | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Under Construction | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	32
Under Construction | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Under Construction | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	32
Under Construction | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Active	'
Power Generation Facilities	'
Number generation facilities	11
Generation capacity (in MW)	1,139
Utility-Scale Solar | Active | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Active | East	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Active | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Active | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Active | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	836
Utility-Scale Solar | Active | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	303
Utility-Scale Solar | Active | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	1,139
Utility-Scale Solar | Active | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Under Construction	'
Power Generation Facilities	'
Number generation facilities	1
Generation capacity (in MW)	26
Utility-Scale Solar | Under Construction | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Under Construction | East	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Under Construction | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Under Construction | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Under Construction | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	26
Utility-Scale Solar | Under Construction | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Utility-Scale Solar | Under Construction | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	26
Utility-Scale Solar | Under Construction | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Wind Farms | Active	'
Power Generation Facilities	'
Number generation facilities	4
Generation capacity (in MW)	448
Wind Farms | Active | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Wind Farms | Active | East	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Wind Farms | Active | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Wind Farms | Active | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Wind Farms | Active | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	347
Wind Farms | Active | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	101
Wind Farms | Active | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	448
Wind Farms | Active | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Active	'
Power Generation Facilities	'
Generation capacity (in MW)	47
Distributed Solar | Active | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Active | East	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Active | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Active | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Active | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	37
Distributed Solar | Active | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	10
Distributed Solar | Active | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	47
Distributed Solar | Active | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Under Construction	'
Power Generation Facilities	'
Generation capacity (in MW)	6
Distributed Solar | Under Construction | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Under Construction | East	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Under Construction | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Under Construction | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Under Construction | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	6
Distributed Solar | Under Construction | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Distributed Solar | Under Construction | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	6
Distributed Solar | Under Construction | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Fossil Fuel | Active	'
Power Generation Facilities	'
Number generation facilities	88
Natural Gas | Active	'
Power Generation Facilities	'
Generation capacity (in MW)	25,007
Natural Gas | Active | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	5,917
Natural Gas | Active | East	'
Power Generation Facilities	'
Generation capacity (in MW)	7,651
Natural Gas | Active | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	3,817
Natural Gas | Active | West	'
Power Generation Facilities	'
Generation capacity (in MW)	6,779
Natural Gas | Active | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Natural Gas | Active | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	843
Natural Gas | Active | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	25,007
Natural Gas | Active | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Coal | Active	'
Power Generation Facilities	'
Generation capacity (in MW)	13,173
Coal | Active | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	4,193
Coal | Active | East	'
Power Generation Facilities	'
Generation capacity (in MW)	6,879
Coal | Active | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	1,496
Coal | Active | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Coal | Active | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Coal | Active | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Coal | Active | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	12,568
Coal | Active | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	605
Oil | Active	'
Power Generation Facilities	'
Generation capacity (in MW)	5,721
Oil | Active | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Oil | Active | East	'
Power Generation Facilities	'
Generation capacity (in MW)	5,531
Oil | Active | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Oil | Active | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Oil | Active | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Oil | Active | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	190
Oil | Active | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	5,721
Oil | Active | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Nuclear fuel | Active	'
Power Generation Facilities	'
Generation capacity (in MW)	1,176
Nuclear fuel | Active | Texas	'
Power Generation Facilities	'
Generation capacity (in MW)	1,176
Nuclear fuel | Active | East	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Nuclear fuel | Active | South Central	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Nuclear fuel | Active | West	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Nuclear fuel | Active | Alternative Energy	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Nuclear fuel | Active | NRG Yield	'
Power Generation Facilities	'
Generation capacity (in MW)	0
Nuclear fuel | Active | Total Domestic	'
Power Generation Facilities	'
Generation capacity (in MW)	1,176
Nuclear fuel | Active | Other (International)	'
Power Generation Facilities	'
Generation capacity (in MW)	0

Nature_of_Business_Details_2

Nature of Business (Details 2) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Jul. 22, 2013

Jul. 22, 2013

Jul. 22, 2013

Jul. 22, 2013

Jul. 22, 2013

Jul. 22, 2013

Sep. 30, 2013

Jul. 22, 2013

Jul. 22, 2013

Jul. 22, 2013

Jul. 22, 2013

In Millions, except Share data, unless otherwise specified

MW

NRG

NRG Yield LLC

Class A Common Stock

Public Shareholders [Member]

NRG Yield LLC

NRG

NRG

Coal and Dual-fired Facilities

Utility-scale Solar and Wind Facilities

Distributed Solar

Thermal

portfolio

NRG Yield, Inc.

NRG Yield, Inc.

NRG

NRG Yield, Inc.

Class B Common Stock

NRG Yield LLC

NRG Yield, Inc.

NRG Yield LLC

NRG Yield LLC

NRG Yield, Inc.

facility

facility

MW

MW

Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock, Voting Interest

'

'

'

'

'

34.50%

'

65.50%

'

'

'

'

'

Sale of Stock, Number of Shares Issued in Transaction

'

'

'

'

22,511,250

'

'

'

'

'

'

'

'

Sale of Stock, Price Per Share

'

'

'

'

$22

'

'

'

'

'

'

'

'

Proceeds from Issuance Initial Public Offering

'

'

'

'

$468

'

'

'

'

'

'

'

'

Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs

'

'

'

'

$27

'

'

'

'

'

'

'

'

Common stock, shares outstanding

323,779,252

322,606,898

'

'

'

'

'

'

42,738,250

'

'

'

'

Sale of Stock, Percentage of Ownership after Transaction

'

'

65.50%

'

'

'

'

'

'

'

'

'

'

Sale of stock, Percentage of Ownership Sold

'

'

'

'

'

'

34.50%

'

'

'

'

'

'

Number of Facilities

'

'

'

'

'

'

'

'

'

3

8

'

'

Number of portfolios of distributed solar facilites

'

'

'

2

'

'

'

'

'

'

'

'

'

Generation capacity (in MW)

45,881

'

'

'

'

'

'

'

'

'

'

1,324

123

Steam and chilled water capacity (in MWt)

1,374

'

'

'

'

'

'

'

'

'

'

'

1,098

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	Months
Funds Deposited by Counterparties	'	'	'	'
Number of months beyond which company can not predict the holding of collateral (in months)	12	'	'	'
Asset Impairments	'	'	'	'
Impairment charge on investment	$99	$2	$495	'
Project Development Costs and Capitalized Interest	'	'	'	'
Amount of interest capitalized	64	104	80	'
Income Taxes	'	'	'	'
Unrecognized tax benefits, more-likely-than-not threshold percentage	50.00%	'	'	'
Revenue Recognition	'	'	'	'
Energy revenues from resales of purchased power	166	151	186	'
Unbilled revenues	356	338	'	318
Gross Receipts and Sales Taxes	'	'	'	'
Gross Receipts Tax	88	79	78	'
Cost of Energy for Retail Operations	'	'	'	'
Transmission and distribution charges not yet billed	90	97	87	'
Foreign Currency Translation and Transaction Gains and Losses	'	'	'	'
Cumulative translation adjustment	15	53	'	72
Marketing and Advertising Expense	'	'	'	'
Marketing and advertising expense	195	197	127	'
Operating Leases, Income Statement, Contingent Revenue	$400	$130	$27	'
South Texas Project	'	'	'	'
Property, Plant and Equipment	'	'	'	'
Ownership Interest (as a percent)	44.00%	'	'	'

Business_Acquisitions_and_Disp2

Business Acquisitions and Dispositions (Acquisitions) (Details) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

9 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

3 Months Ended

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 18, 2012

Dec. 31, 2013

Oct. 18, 2013

Dec. 31, 2013

Dec. 31, 2013

Aug. 07, 2013

Feb. 14, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2013

Dec. 14, 2012

Sep. 30, 2011

Sep. 30, 2012

Dec. 31, 2011

Sep. 30, 2012

Sep. 30, 2012

Sep. 30, 2012

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Mar. 31, 2012

Sep. 30, 2011

Sep. 30, 2012

Dec. 31, 2012

Oct. 31, 2013

Sep. 30, 2012

Aug. 05, 2011

Sep. 30, 2013

Apr. 05, 2011

Apr. 05, 2011

Apr. 05, 2011

Apr. 05, 2011

Apr. 05, 2011

Apr. 05, 2011

Oct. 18, 2013

Dec. 31, 2011

MW

NRG Solar AC Holdings LLC

Active

Edison Mission Energy

Energy Systems Company

Energy Systems Company

Gregory

GenOn Energy

GenOn Energy

GenOn Energy

GenOn Energy

GenOn Energy

Energy Plus

Energy Plus

Energy Plus

Energy Plus

Energy Plus

Energy Plus

Solar Acquisitions

Solar Acquisitions

Solar Acquisitions

Solar Acquisitions

California Valley Solar Ranch

California Valley Solar Ranch

California Valley Solar Ranch

California Valley Solar Ranch

California Valley Solar Ranch

Agua Caliente

Agua Caliente

Ivanpah Solar Electric Generating System

Interest Maintained By Bright Source Energy, Inc.

Interest Aquired by Wholly-Owned Subsidiary of Google

Ivanpah Solar Electric Generating System Facility One

Ivanpah Solar Electric Generating System Facility Two

Ivanpah Solar Electric Generating System Facility Three

Plan

Plan

MW

MW

Customer Relationships

MW

MW

customer

Customer Relationships

Marketing Partnerships

Trade Names

facility

year

Phase 1

Phases 2 and 4

Final Phase [Domain]

Final Phase [Domain]

year

Active

facility

MW

MW

MW

Edison Mission Energy

Solar Acquisitions

MW

MW

MW

MW

MW

MW

MW

year

MW

Business Acquisition

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation capacity (in MW)

'

45,881

'

'

'

46,711

8,000

'

'

388

'

'

'

'

21,440

'

'

'

'

'

'

'

'

'

'

250

22

105

102

21

290

290

378

'

'

126

133

133

'

'

Payments to Acquire Business, Estimated

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$2,600,000,000

'

Shares issued for GenOn acquisition

'

'

'

'

'

'

'

'

'

'

93,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,671,977

'

Business Acquisition, Equity Interest Issued or Issuable, Value Assigned

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

350,000,000

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents

'

'

'

'

'

'

'

'

'

32,000,000

'

'

'

'

983,000,000

5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100,000,000

'

Business Combination, Estimated Consideration Transferred, Estimated Liabilities Incurred

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700,000,000

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,203,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000,000

'

Environmental Capital Expenditures, Estimated

'

332,000,000

'

'

'

'

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments to Acquire Business, Fee Contingently Receivable

'

'

'

'

'

'

65,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments to Acquire Businesses, Net of Cash Acquired

'

494,000,000

81,000,000

377,000,000

'

'

'

'

'

245,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Steam and chilled water capacity (in MWt)

'

1,374

'

'

'

'

'

'

'

160

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

BusinessAcquisitionEquityInterestIssuedOrIssuableExchangeRatio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12.16%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares of outstanding common stock issued for Genon acquisition (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

29.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Consideration Paid, Equity Interests Issued and Issuable

28,000,000

'

'

'

'

'

'

'

'

'

2,188,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,385,000,000

'

'

'

'

'

'

'

'

'

60,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Other Assets

'

'

'

'

'

'

'

'

'

'

'

'

28,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Other Assets, Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,413,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment

'

'

'

'

'

'

'

60,000,000

'

248,000,000

'

'

'

'

3,936,000,000

'

'

'

'

'

'

'

'

'

767,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Assets, Current

'

7,596,000,000

7,972,000,000

'

'

'

'

'

'

13,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment

'

'

'

'

'

'

'

'

'

'

'

'

-115,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment, Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,821,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition Purchase Price Allocation, Derivative Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,157,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Assets Noncurrent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,265,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Deferred Taxes Asset (Liability), Net, Noncurrent

'

'

'

'

'

'

'

'

'

'

'

'

-58,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Deferred Taxes Asset (Liability), Net, Noncurrent, Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,207,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,726,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Assets

'

'

'

'

'

'

'

'

'

'

'

'

-145,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Assets Acquired, Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,581,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Other Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,312,000,000

'

'

'

'

'

'

'

'

'

19,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Current and Noncurrent Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

54,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Other Liabilities, Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,366,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Out of Market Contracts and Leases

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,064,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Out of Market Contracts and Leases

'

'

'

'

'

'

'

'

'

'

'

'

62,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Out of Market Contracts and Leases, Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,126,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Derivative Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

399,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncurrent Liabilities Longterm Debt

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt, Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,206,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities

'

'

'

'

'

'

'

'

'

16,000,000

'

'

'

'

6,978,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

119,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Liabilities Assumed, Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,097,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,748,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Net Assets Acquired

'

'

'

'

'

'

'

'

'

'

'

'

-264,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net Adjusted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,484,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Bargain Purchase, Gain Recognized, Amount

'

0

296,000,000

0

'

'

'

'

'

'

'

560,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Bargain Purchase, Gain Recognized, Amount

'

'

'

'

'

'

'

'

'

'

'

'

-264,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Bargain Purchase, Gain Recognized, Amount, Adjusted

'

'

'

'

'

'

'

'

'

'

'

296,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Payments to Acquire Businesses

'

'

'

'

'

'

'

120,000,000

'

'

'

'

'

'

'

194,000,000

'

'

'

'

'

'

165,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Customers Acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

188,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles

'

'

'

'

'

'

'

'

59,000,000

'

'

'

'

'

'

'

'

'

63,000,000

88,000,000

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill

'

1,985,000,000

1,956,000,000

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

29,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Finite-Lived Intangible Asset, Useful Life

'

'

'

'

'

'

'

'

'33 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Utility Scale Solar Facilities Acquired a Stake In

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Capital Contributions From Parent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

868,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Letters of Credit Contributed to Project

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

66,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Contributions from Affiliates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

413,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

64,000,000

Business Acquisition, Percentage of Voting Interests Acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

100.00%

'

50.10%

'

'

'

'

'

'

'

Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners

'

'

'

'

49.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Power Purchase Agreement Period (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

'

'

'

'

25

'

'

'

'

'

'

'

'

'

Ownership interest (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21.80%

28.10%

'

'

'

'

'

Business Acquisition Number of Facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

Power Purchase Agreement Period, Low End of Range (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20

'

'

'

'

'

'

'

Power Purchase Agreement Period, High End of Range (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$489,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business_Acquisitions_and_Disp3

Business Acquisitions and Dispositions (Dispositions) (Details 2)	0 Months Ended				0 Months Ended						0 Months Ended
In Millions, unless otherwise specified	Jul. 19, 2012	Dec. 31, 2013	Jul. 17, 2012	Jan. 18, 2012	Jan. 18, 2012	Jul. 17, 2012	Jul. 17, 2012	Jul. 17, 2012	Jul. 17, 2012	Jul. 17, 2012	Dec. 31, 2013
	USD ($)	MW	USD ($)	NRG Solar AC Holdings LLC	Sale of Interest in Agua Caliente	Schkopau	Kraftwerke Schkopau	Kraftwerke Schkopau Betriebsgesllshaft mbH	Currency Swap	Saale Energie GmbH	Energy Systems Company
			MW		USD ($)	MW			EUR (€)		Customer Relationships
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations	'	'	'	'	'	'	'	'	'	'	'
Finite-Lived Intangible Asset, Useful Life	'	'	'	'	'	'	'	'	'	'	'33 years
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	'	'	'	49.00%	49.00%	'	'	'	'	'	'
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Sale of Interest by Parent	'	'	'	'	$122	'	'	'	'	'	'
Investment Owned, Percent of Net Assets	'	'	'	'	'	'	'	'	'	100.00%	'
Ownership interest (as a percent)	'	'	'	'	'	'	41.90%	44.40%	'	'	'
Power Generation, Participation, Megawatts	'	'	400	'	'	'	'	'	'	'	'
Generation capacity (in MW)	'	45,881	'	'	'	900	'	'	'	'	'
Derivative, Notional Amount	'	'	'	'	'	'	'	'	141	'	'
Proceeds from Sale of Property, Plant, and Equipment	174	'	'	'	'	'	'	'	'	'	'
Gain (Loss) on Derivative Instruments, Net, Pretax	4	'	'	'	'	'	'	'	'	'	'
Assets Held-for-sale, Long Lived	'	'	$38	'	'	'	'	'	'	'	'

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets	'	'
Notes receivable (a)	$99	$88
Liabilities	'	'
Long-term debt, including current portion	16,804	15,866
Carrying Amount	'	'
Assets	'	'
Notes receivable (a)	99	88
Liabilities	'	'
Long-term debt, including current portion	16,804	15,866
Fair Value	'	'
Assets	'	'
Notes receivable (a)	99	88
Liabilities	'	'
Long-term debt, including current portion	$17,222	$16,492

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Details 2) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	$1,639		$3,306
Derivative liabilities	1,250		2,481
Commodity contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	1,619		3,303
Derivative liabilities	1,181		2,338
Interest rate contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	20		3
Derivative liabilities	69		143
Fair Value, Measurements, Recurring	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value	1		'
Fair Value, Measurements, Recurring | Level 1	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Debt securities	0		0
Available-for-sale Securities	2		'
Other	37	[1]	22	[2]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value	1		'
Total assets	728		1,756
Total liabilities	216		1,144
Fair Value, Measurements, Recurring | Level 1 | Commodity contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	346		1,457
Derivative liabilities	216		1,144
Fair Value, Measurements, Recurring | Level 1 | Interest rate contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	0		0
Derivative liabilities	0		0
Fair Value, Measurements, Recurring | Level 1 | Cash and cash equivalents	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	26		10
Fair Value, Measurements, Recurring | Level 1 | U.S. government and federal agency obligations	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	40		33
Fair Value, Measurements, Recurring | Level 1 | Federal agency mortgage-backed securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 1 | Commercial mortgage-backed securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 1 | Corporate debt securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 1 | Equity securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	276		233
Fair Value, Measurements, Recurring | Level 1 | Foreign government fixed income securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 2	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Debt securities	0		0
Available-for-sale Securities	0		'
Other	0	[1]	0	[2]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value	0		'
Total assets	1,299		1,864
Total liabilities	900		1,190
Fair Value, Measurements, Recurring | Level 2 | Commodity contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	1,126		1,711
Derivative liabilities	831		1,047
Fair Value, Measurements, Recurring | Level 2 | Interest rate contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	20		3
Derivative liabilities	69		143
Fair Value, Measurements, Recurring | Level 2 | Cash and cash equivalents	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 2 | U.S. government and federal agency obligations	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	5		0
Fair Value, Measurements, Recurring | Level 2 | Federal agency mortgage-backed securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	62		59
Fair Value, Measurements, Recurring | Level 2 | Commercial mortgage-backed securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	14		9
Fair Value, Measurements, Recurring | Level 2 | Corporate debt securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	70		80
Fair Value, Measurements, Recurring | Level 2 | Equity securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 2 | Foreign government fixed income securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	2		2
Fair Value, Measurements, Recurring | Level 3	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Debt securities	16		12
Available-for-sale Securities	0		'
Other	10	[1]	0	[2]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value	0		'
Total assets	229		194
Total liabilities	134		147
Fair Value, Measurements, Recurring | Level 3 | Commodity contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	147		135
Derivative liabilities	134		147
Fair Value, Measurements, Recurring | Level 3 | Interest rate contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	0		0
Derivative liabilities	0		0
Fair Value, Measurements, Recurring | Level 3 | Cash and cash equivalents	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 3 | U.S. government and federal agency obligations	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 3 | Federal agency mortgage-backed securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 3 | Commercial mortgage-backed securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 3 | Corporate debt securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Level 3 | Equity securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	56		47
Fair Value, Measurements, Recurring | Level 3 | Foreign government fixed income securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	0		0
Fair Value, Measurements, Recurring | Fair Value	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Debt securities	16		12
Available-for-sale Securities	2		'
Other	47	[1]	22	[2]
Total assets	2,256		3,814
Total liabilities	1,250		2,481
Fair Value, Measurements, Recurring | Fair Value | Commodity contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	1,619		3,303
Derivative liabilities	1,181		2,338
Fair Value, Measurements, Recurring | Fair Value | Interest rate contracts	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Derivative assets	20		3
Derivative liabilities	69		143
Fair Value, Measurements, Recurring | Fair Value | Cash and cash equivalents	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	26		10
Fair Value, Measurements, Recurring | Fair Value | U.S. government and federal agency obligations	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	45		33
Fair Value, Measurements, Recurring | Fair Value | Federal agency mortgage-backed securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	62		59
Fair Value, Measurements, Recurring | Fair Value | Commercial mortgage-backed securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	14		9
Fair Value, Measurements, Recurring | Fair Value | Corporate debt securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	70		80
Fair Value, Measurements, Recurring | Fair Value | Equity securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	332		280
Fair Value, Measurements, Recurring | Fair Value | Foreign government fixed income securities	'		'
Investment in available-for-sale securities (classified within other non-current assets):	'		'
Trust fund investments	$2		$2
[1]	Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for some key and highly compensated employees and a total return swap that does not meet the definition of a derivative.
[2]	Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for some key and highly compensated employees.

Fair_Value_of_Financial_Instru4

Fair Value of Financial Instruments (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements	'		'
Balance at the beginning of the period	$47		$57
Total gains and losses (realized/unrealized):	'		'
Included in OCI	4		5
Included in earnings	-12		-13
Included in nuclear decommissioning obligations	10		5
Purchases	16		8
Contracts acquired in GenOn acquisition	'		18
Transfers into Level 3	6	[1]	-33	[1]
Transfers out of Level 3	27	[1]	0	[1]
Balance at the end of the period	95		47
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period	1		-3
Debt Securities	'		'
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements	'		'
Balance at the beginning of the period	12		7
Total gains and losses (realized/unrealized):	'		'
Included in OCI	4		5
Included in earnings	0		0
Included in nuclear decommissioning obligations	0		0
Purchases	0		0
Contracts acquired in GenOn acquisition	'		0
Transfers into Level 3	0	[1]	0	[1]
Transfers out of Level 3	0	[1]	0	[1]
Balance at the end of the period	16		12
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period	0		0
Trust Fund Investments	'		'
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements	'		'
Balance at the beginning of the period	47		42
Total gains and losses (realized/unrealized):	'		'
Included in OCI	0		0
Included in earnings	0		0
Included in nuclear decommissioning obligations	10		5
Purchases	2		0
Contracts acquired in GenOn acquisition	'		0
Transfers into Level 3	0	[1]	0	[1]
Transfers out of Level 3	0	[1]	0	[1]
Balance at the end of the period	56		47
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period	0		0
Derivatives	'		'
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements	'		'
Balance at the beginning of the period	-12	[2]	8	[2]
Total gains and losses (realized/unrealized):	'		'
Included in OCI	0	[2]	0	[2]
Included in earnings	-12	[2]	-13	[2]
Included in nuclear decommissioning obligations	0	[2]	0	[2]
Purchases	4	[2]	8	[2]
Contracts acquired in GenOn acquisition	'		18	[2]
Transfers into Level 3	6	[1],[2]	-33	[1],[2]
Transfers out of Level 3	27	[1],[2]	0	[1],[2]
Balance at the end of the period	13	[2]	-12	[2]
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period	$1	[2]	($3)	[2]
[1]	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
[2]	Consists of derivatives assets and liabilities, net.

Fair_Value_of_Financial_Instru5

Fair Value of Financial Instruments (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Derivative Fair Value Meaurements and Concentration of Credit Risk	'		'
Total derivative assets valued with prices provied by models and other valuation techniques (as a percent)	9.00%		'
Total derivative liabilities valued with prices provied by models and other valuation techniques (as a percent)	11.00%		'
Increase/(Decrease) in fair value as a result of the credit reserve	$1		'
Increase/(Decrease) in fair value as a result of the credit reserve, portion recorded in operating revenue and cost of operations	1		'
Cash collateral paid in support of energy risk management activities	276		229
Cash collateral received in support of energy risk management activities	63		271
Counterparty credit exposure, excluding credit risk exposure under certain long term agreements	813		'
Counterparty credit exposure, collateral held (cash and letters of credit) against positions	5		'
Counterparty credit exposure, net	808		'
Company's exposure before collateral expected to roll off by the end of 2015 (as a percent)	87.00%		'
Net exposure (as a percent)	100.00%	[1]	'
Counterparty credit risk exposure to certain counterparties, threshold (as a percent)	10.00%		'
Aggregate counterparty credit risk exposure for counterparties representing exposure above threshold percentage	349		'
Estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements for the next 5 years	2,300		'
Period of estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements (in years)	'5 years		'
Investment grade	'		'
Derivative Fair Value Meaurements and Concentration of Credit Risk	'		'
Net exposure (as a percent)	94.00%	[1]	'
External Credit Rating Not Rated [Member]	'		'
Derivative Fair Value Meaurements and Concentration of Credit Risk	'		'
Net exposure (as a percent)	6.00%	[1]	'
Financial institutions	'		'
Derivative Fair Value Meaurements and Concentration of Credit Risk	'		'
Net exposure (as a percent)	52.00%	[1]	'
Utilities, energy merchants, marketers and other	'		'
Derivative Fair Value Meaurements and Concentration of Credit Risk	'		'
Net exposure (as a percent)	29.00%	[1]	'
Coal and emissions	'		'
Derivative Fair Value Meaurements and Concentration of Credit Risk	'		'
Net exposure (as a percent)	1.00%	[1]	'
ISOs	'		'
Derivative Fair Value Meaurements and Concentration of Credit Risk	'		'
Net exposure (as a percent)	18.00%	[1]	'
NRG Yield, Inc.	'		'
Derivative Fair Value Meaurements and Concentration of Credit Risk	'		'
Estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements for the next 5 years	$797		'
[1]	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.

Accounting_for_Derivative_Inst2

Accounting for Derivative Instruments and Hedging Activities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
	T	T
Fair value of the derivative instrument	'	'
Derivative assets	1,639	3,306
Derivative liabilities	1,250	2,481
Derivatives Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	14	3
Derivative liabilities	66	129
Derivatives Not Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	1,625	3,303
Derivative liabilities	1,184	2,352
Interest rate contracts current | Derivatives Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	0	0
Derivative liabilities	35	29
Interest rate contracts current | Derivatives Not Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	0	0
Derivative liabilities	4	7
Interest rate contracts long-term | Derivatives Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	14	3
Derivative liabilities	29	96
Interest rate contracts long-term | Derivatives Not Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	6	0
Derivative liabilities	1	11
Commodity contracts current | Derivatives Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	0	0
Derivative liabilities	1	3
Commodity contracts current | Derivatives Not Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	1,328	2,644
Derivative liabilities	1,015	1,942
Commodity contracts long-term | Derivatives Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	0	0
Derivative liabilities	1	1
Commodity contracts long-term | Derivatives Not Designated as Cash Flow Hedges	'	'
Fair value of the derivative instrument	'	'
Derivative assets	291	659
Derivative liabilities	164	392
Short Ton | Emissions	'	'
Volumetric Underlying Derivative Transactions [Abstract]	'	'
Derivative, Nonmonetary Notional Amount, Mass	0	-1,000,000
Short Ton | Coal	'	'
Volumetric Underlying Derivative Transactions [Abstract]	'	'
Derivative, Nonmonetary Notional Amount, Mass	51,000,000	37,000,000
MMbtu | Natural Gas	'	'
Volumetric Underlying Derivative Transactions [Abstract]	'	'
Derivative, Nonmonetary Notional Amount, Energy Measure	-166,000,000	-413,000,000
Barrel | Oil	'	'
Volumetric Underlying Derivative Transactions [Abstract]	'	'
Derivative, Nonmonetary Notional Amount, Volume	1,000,000	1,000,000
MWh | Power	'	'
Volumetric Underlying Derivative Transactions [Abstract]	'	'
Derivative, Nonmonetary Notional Amount, Energy Measure	-27,000,000	-14,000,000
Dollars | Interest	'	'
Volumetric Underlying Derivative Transactions [Abstract]	'	'
Derivative, Notional Amount	1,444	2,612

Accounting_for_Derivative_Inst3

Accounting for Derivative Instruments and Hedging Activities (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid	'	'
Gross Amount of Recognized Derivative Assets	$1,639	$3,306
Cash Collateral (Held)	-63	-271
Gross Amounts of Recognized Derivative Liabilities	-1,250	-2,481
Cash Collateral Posted	276	229
Gross Amounts of Recognized Assets / Liabilities	389	825
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	-44	-346
Net Amount	345	479
Commodity contracts	'	'
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid	'	'
Gross Amount of Recognized Derivative Assets	1,619	3,303
Derivative Instruments	-1,032	-2,024
Cash Collateral (Held)	-62	-374
Net Amount	525	905
Gross Amounts of Recognized Derivative Liabilities	-1,181	-2,338
Derivative Instruments	1,032	2,024
Cash Collateral Posted	18	28
Net Amount	-131	-286
Gross Amounts of Recognized Assets / Liabilities	438	965
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	-44	-346
Net Amount	394	619
Interest rate contracts	'	'
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid	'	'
Gross Amount of Recognized Derivative Assets	20	3
Derivative Instruments	-12	0
Cash Collateral (Held)	0	0
Net Amount	8	3
Gross Amounts of Recognized Derivative Liabilities	-69	-143
Derivative Instruments	12	0
Cash Collateral Posted	0	0
Net Amount	-57	-143
Gross Amounts of Recognized Assets / Liabilities	-49	-140
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	0	0
Net Amount	($49)	($140)

Accounting_for_Derivative_Inst4

Accounting for Derivative Instruments and Hedging Activities (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative	'	'	'
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	($31)	($121)	($362)
Accumulated Other Comprehensive Income	'	'	'
Accumulated OCI beginning balance	-31	132	441
Mark-to-market of cash flow hedge accounting contracts	39	-42	53
Accumulated OCI ending balance, net of tax	-23	-31	132
Accumulated OCI ending balance, tax	0	7	87
Losses expected to be realized from OCI during the next 12 months, net of $8 tax	-15	'	'
Gains/(losses) expected to be realized from OCI during the next 12 months, tax	0	'	'
Losses recognized in income from the ineffective portion of cash flow hedges	'	-51	'
Gains recognized in income from the ineffective portion of cash flow hedges	'	'	31
Unrealized mark-to-market results	'	'	'
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	-105	-247	-54
Reversal of (gain)/loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions	-357	20	-107
Net unrealized gains/(losses) on open positions related to economic hedges	177	10	-33
(Losses)/gains on ineffectiveness associated with open positions treated as cash flow hedges	0	-51	28
Total unrealized mark-to-market (losses)/gains for economic hedging activities	-285	-268	156
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	-50	-60	21
Net unrealized gains on open positions related to trading activity	7	46	42
Total unrealized mark-to-market (losses)/gains for trading activity	-43	-14	63
Total unrealized (losses)/gains	-328	-282	219
Impact of derivative instruments to statement of operations	'	'	'
Total unrealized (losses)/gains	-328	-282	219
Gain/(loss) from economic hedge position	-177	10	'
Credit Risk Related Contingent Features	'	'	'
Collateral required for contracts with adequate assurance clauses in net liability positions	85	'	'
Collateral required for contracts with credit rating contingent features	15	'	'
Collateral due on net liability position that has not been called by a certain marginable agreement counterparty	34	'	'
Energy commodities	'	'	'
Derivative	'	'	'
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	-51	-144	-374
Accumulated Other Comprehensive Income	'	'	'
Accumulated OCI beginning balance	41	188	488
Mark-to-market of cash flow hedge accounting contracts	9	-3	74
Accumulated OCI ending balance, net of tax	-1	41	188
Losses expected to be realized from OCI during the next 12 months, net of $8 tax	-1	'	'
Losses recognized in income from the ineffective portion of cash flow hedges	'	-51	'
Gains recognized in income from the ineffective portion of cash flow hedges	'	'	28
Unrealized mark-to-market results	'	'	'
Total unrealized (losses)/gains	-328	-282	219
Impact of derivative instruments to statement of operations	'	'	'
Total unrealized (losses)/gains	-328	-282	219
Energy commodities | Unrealized (losses)/gains included in operating revenues	'	'	'
Unrealized mark-to-market results	'	'	'
Total unrealized (losses)/gains	-621	-464	388
Impact of derivative instruments to statement of operations	'	'	'
Total unrealized (losses)/gains	-621	-464	388
Energy commodities | Unrealized gains/(losses) included in cost of operations	'	'	'
Unrealized mark-to-market results	'	'	'
Total unrealized (losses)/gains	293	182	-169
Impact of derivative instruments to statement of operations	'	'	'
Total unrealized (losses)/gains	293	182	-169
Interest rate contracts	'	'	'
Derivative	'	'	'
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	20	23	12
Accumulated Other Comprehensive Income	'	'	'
Accumulated OCI beginning balance	-72	-56	-47
Mark-to-market of cash flow hedge accounting contracts	30	-39	-21
Accumulated OCI ending balance, net of tax	-22	-72	-56
Losses expected to be realized from OCI during the next 12 months, net of $8 tax	-14	'	'
Losses recognized in income from the ineffective portion of cash flow hedges	'	0	'
Gains recognized in income from the ineffective portion of cash flow hedges	'	'	3
Unrealized mark-to-market results	'	'	'
Total unrealized (losses)/gains	15	-8	2
Impact of derivative instruments to statement of operations	'	'	'
Total unrealized (losses)/gains	15	-8	2
CVSR | Interest rate contracts	'	'	'
Discontinuation of Cash Flow Hedge [Abstract]	'	'	'
Loss previously deferred in OCI recognized in earnings resulting from discontinued cash flow hedge accounting	5	'	'
Alpine | Interest rate contracts	'	'	'
Discontinuation of Cash Flow Hedge [Abstract]	'	'	'
Loss previously deferred in OCI recognized in earnings resulting from discontinued cash flow hedge accounting	'	$4	'

Nuclear_Decommissioning_Trust_2

Nuclear Decommissioning Trust Fund (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Nuclear decommissioning trust fund disclosure	'	'		'
Fair Value	$551	$473		'
Unrealized Gains	207	151	[1]	'
Unrealized Losses	3	'		'
Proceeds from sales of available-for-sale securities and the related realized gains and losses	'	'		'
Realized gains	25	12		4
Realized losses	-8	-7		-3
Proceeds from sale of securities	488	399		385
Cash and cash equivalents	'	'		'
Nuclear decommissioning trust fund disclosure	'	'		'
Fair Value	26	10		'
Unrealized Gains	0	0	[1]	'
Unrealized Losses	0	'		'
Weighted- average maturities (in years)	0	0		'
U.S. government and federal agency obligations	'	'		'
Nuclear decommissioning trust fund disclosure	'	'		'
Fair Value	45	33		'
Unrealized Gains	1	2	[1]	'
Unrealized Losses	1	'		'
Weighted- average maturities (in years)	9	10		'
Federal agency mortgage-backed securities	'	'		'
Nuclear decommissioning trust fund disclosure	'	'		'
Fair Value	62	59		'
Unrealized Gains	1	2	[1]	'
Unrealized Losses	1	'		'
Weighted- average maturities (in years)	24	23		'
Commercial mortgage-backed securities	'	'		'
Nuclear decommissioning trust fund disclosure	'	'		'
Fair Value	14	9		'
Unrealized Gains	0	0	[1]	'
Unrealized Losses	0	'		'
Weighted- average maturities (in years)	29	30		'
Corporate debt securities	'	'		'
Nuclear decommissioning trust fund disclosure	'	'		'
Fair Value	70	80		'
Unrealized Gains	1	4	[1]	'
Unrealized Losses	1	'		'
Weighted- average maturities (in years)	9	11		'
Equity securities	'	'		'
Nuclear decommissioning trust fund disclosure	'	'		'
Fair Value	332	280		'
Unrealized Gains	204	143	[1]	'
Unrealized Losses	0	'		'
Weighted- average maturities (in years)	0	0		'
Foreign government fixed income securities	'	'		'
Nuclear decommissioning trust fund disclosure	'	'		'
Fair Value	2	2		'
Unrealized Gains	0	0	[1]	'
Unrealized Losses	$0	'		'
Weighted- average maturities (in years)	9	6		'
South Texas Project	'	'		'
Nuclear decommissioning trust fund disclosure	'	'		'
Ownership Interest (as a percent)	44.00%	'		'
[1]	There are no unrealized losses as of December 31, 2012.

Inventory_Details

Inventory (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Inventory Disclosure [Abstract]	'	'
Fuel oil	$259	$181
Coal/Lignite	290	405
Natural gas	15	12
Spare parts	316	301
Other	18	4
Total Inventory	$898	$903

Notes_Receivable_Details

Notes Receivable (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Notes Receivable	'		'
Notes receivable (a)	$99		$88
Notes receivable, current	26	[1]	9	[1]
Notes receivable, noncurrent	73		79
Other non-affiliates	'		'
Notes Receivable	'		'
Notes receivable (a)	97	[2]	82	[2]
Avenal Solar Holdings LLC	'		'
Notes Receivable	'		'
Notes receivable, related parties	2	[3]	6	[3]
Note receivable, related parties, face amount	$35		'
Note receivable, related parties, interest rate (as a percent)	4.50%		4.50%
[1]	The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.
[2]	Borrego, El Segundo Energy Center and CVSR's agreements with their respective transmission owners to provide financing for required network upgrades. The notes will be repaid within a five year period following the date each facility reaches commercial operations.
[3]	NRG entered into a long-term $35 million note receivable facility with Avenal Solar Holdings LLC, to fund project liquidity needs in 2011.

Property_Plant_and_Equipment_D

Property, Plant and Equipment (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment	'	'
Total property, plant and equipment	$26,424	$25,561
Accumulated depreciation	-6,573	-5,408
Net property, plant and equipment	19,851	20,153
Facilities and equipment	'	'
Property, Plant and Equipment	'	'
Total property, plant and equipment	22,087	19,571
Land and improvements	'	'
Property, Plant and Equipment	'	'
Total property, plant and equipment	801	793
Nuclear fuel	'	'
Property, Plant and Equipment	'	'
Total property, plant and equipment	463	414
Depreciable lives (in years)	'5 years	'
Office furnishings and equipment	'	'
Property, Plant and Equipment	'	'
Total property, plant and equipment	298	355
Construction in progress	'	'
Property, Plant and Equipment	'	'
Total property, plant and equipment	$2,775	$4,428
Minimum | Facilities and equipment	'	'
Property, Plant and Equipment	'	'
Depreciable lives (in years)	'1 year	'
Minimum | Office furnishings and equipment	'	'
Property, Plant and Equipment	'	'
Depreciable lives (in years)	'2 years	'
Maximum | Facilities and equipment	'	'
Property, Plant and Equipment	'	'
Depreciable lives (in years)	'40 years	'
Maximum | Office furnishings and equipment	'	'
Property, Plant and Equipment	'	'
Depreciable lives (in years)	'10 years	'

Asset_Impairments_Details

Asset Impairments (Details) (USD $)	12 Months Ended			3 Months Ended	12 Months Ended			3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
				Indian River	Emission Allowances	NINA Investment	NINA Investment	Gladstone Power Station
Asset Impairments	'	'	'	'	'	'	'	'
Impairment losses	$459	$0	$160	$459	$160	$2	$495	$92
Noncontrolling Interest, Ownership Percentage by Parent	'	'	'	'	'	'	'	37.50%

Goodwill_and_Other_Intangibles1

Goodwill and Other Intangibles (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2006

Dec. 31, 2010

Dec. 31, 2011

Sep. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 14, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Texas Genco

Green Mountain Energy

Energy Plus

Energy Plus

Emission Allowances

Emission Allowances

Emission Allowances

Development Rights

Development Rights

Energy Supply

Energy Supply

Energy Supply

Fuel

Fuel

Fuel

Customer

Customer

Customer

Customer Relationships

Customer Relationships

Customer Relationships

Marketing Partnerships

Marketing Partnerships

Marketing Partnerships

Trade Names

Trade Names

Trade Names

Other

Other

Other

Leases

Gas Transportation

Out of Market Contracts

Out of Market Contracts

Out of Market Contracts

Out of Market Contracts

GenOn Energy

GenOn Energy

Power Contracts

Leases

Gas Transportation

Goodwill and Other Intangibles

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill

$1,985

$1,956

'

'

'

'

'

$29

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill in connection with acquisition

'

'

'

'

1,700

144

29

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill deductible for U.S. income tax purposes

573

609

'

594

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment charge on the Company's Acid Rain SO2 emission allowances

'

160

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Components of NRG's intangible assets subject to amortization

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross amount at the beginning of the period

2,916

2,871

'

'

'

'

'

'

793

783

'

24

24

54

54

'

72

72

'

859

859

'

640

634

'

88

88

'

318

318

'

68

39

'

'

'

'

'

'

'

Purchases

118

36

'

'

'

'

'

'

76

18

'

0

0

0

0

'

0

0

'

0

0

'

14

0

'

0

0

'

0

0

'

28

18

'

'

'

'

'

'

'

Acquisition of businesses

99

69

'

'

'

'

'

'

0

53

'

0

0

0

0

'

0

0

'

0

0

'

89

6

'

0

0

'

0

0

'

10

10

'

'

'

'

'

'

'

Usage

-14

-13

'

'

'

'

'

'

0

0

'

0

0

0

0

'

0

0

'

0

0

'

0

0

'

0

0

'

0

0

'

-14

-13

'

'

'

'

'

'

'

Sales

'

-4

'

'

'

'

'

'

'

-4

'

'

0

'

0

'

'

0

'

'

0

'

'

0

'

'

0

'

'

0

'

'

0

'

'

'

'

'

'

'

Write-off of fully amortized balances

'

56

'

'

'

'

'

'

'

56

'

'

0

'

0

'

'

0

'

'

0

'

'

0

'

'

0

'

'

0

'

'

0

'

'

'

'

'

'

'

Other

-2

13

'

'

'

'

'

'

2

-1

'

-5

0

0

0

'

0

0

'

0

0

'

0

0

'

0

0

'

0

0

'

1

14

'

'

'

'

'

'

'

Gross amount at the end of the period

3,117

2,916

2,871

'

'

'

'

'

871

793

783

19

24

54

54

54

72

72

72

859

859

859

743

640

634

88

88

88

318

318

318

93

68

39

'

'

'

'

'

'

Less accumulated amortization

-1,977

-1,706

'

'

'

'

'

'

-433

-329

'

0

0

-36

-30

'

-61

-59

'

-847

-794

'

-487

-415

'

-12

-4

'

-93

-72

'

-8

-3

'

'

'

'

'

'

'

Net carrying amount

1,140

1,210

'

'

'

'

'

'

438

464

'

19

24

18

24

'

11

13

'

12

65

'

256

225

'

76

84

'

225

246

'

85

65

'

'

'

'

'

'

'

Amortization of intangible assets

279

310

388

'

'

'

'

'

104

50

66

'

'

6

5

4

2

2

2

53

119

185

72

98

109

8

4

0

29

30

22

5

2

0

'

'

'

'

'

'

Estimated amortization related to NRG's finite-lived intangible assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated intangible assets amortization, 2014

184

'

'

'

'

'

'

'

77

'

'

1

'

6

'

'

2

'

'

1

'

'

61

'

'

15

'

'

21

'

'

'

'

'

'

'

'

'

'

'

Estimated intangible assets amortization, 2015

155

'

'

'

'

'

'

'

65

'

'

1

'

6

'

'

2

'

'

1

'

'

45

'

'

14

'

'

21

'

'

'

'

'

'

'

'

'

'

'

Estimated intangible assets amortization, 2016

135

'

'

'

'

'

'

'

64

'

'

1

'

6

'

'

2

'

'

1

'

'

31

'

'

9

'

'

21

'

'

'

'

'

'

'

'

'

'

'

Estimated intangible assets amortization, 2017

114

'

'

'

'

'

'

'

65

'

'

1

'

0

'

'

0

'

'

1

'

'

21

'

'

5

'

'

21

'

'

'

'

'

'

'

'

'

'

'

Estimated intangible assets amortization, 2018

106

'

'

'

'

'

'

'

68

'

'

1

'

0

'

'

0

'

'

1

'

'

10

'

'

5

'

'

21

'

'

'

'

'

'

'

'

'

'

'

Weighted average remaining amortization period (in years)

'

'

'

'

'

'

'

'

'28 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Emission allowances held-for-sale and included in other non current assets

24

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Out-of-market contracts

1,177

1,278

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

790

327

'

'

'

'

Estimated amortization related to NRG's out-of-market contracts

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated out-of-market amortization, 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

92

17

39

36

Estimated out-of-market amortization, 2015

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

93

17

39

37

Estimated out-of-market amortization, 2016

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

99

18

39

42

Estimated out-of-market amortization, 2017

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

94

18

39

37

Estimated out-of-market amortization, 2018

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$90

$19

$39

$32

Debt_and_Capital_Leases_Debt_S

Debt and Capital Leases (Debt Schedule)(Details) (USD $)

12 Months Ended

2 Months Ended

2 Months Ended

2 Months Ended

12 Months Ended

0 Months Ended

4 Months Ended

7 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Feb. 27, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Feb. 27, 2013

Dec. 31, 2013

Dec. 31, 2012

Feb. 27, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jun. 04, 2013

Jun. 04, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2002

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Recourse Debt

Recourse Debt

Non Recourse Debt

Non Recourse Debt

Senior notes, due 2018

Senior notes, due 2018

Senior notes, due 2018

7.625% Senior notes, due 2019

7.625% Senior notes, due 2019

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

Senior notes, due 2020

Senior notes, due 2020

Senior notes, due 2020

Senior notes, due 2021

Senior notes, due 2021

Senior notes, due 2023

Senior notes, due 2023

Term loan facility, due 2018

Term loan facility, due 2018

Term loan facility, due 2018

Term loan facility, due 2018

Term loan facility, due 2018

Term loan facility, due 2018

Term loan facility, due 2018

Indian River Power LLC, tax exempt bonds, due 2040 and 2045

Indian River Power LLC, tax exempt bonds, due 2040 and 2045

Dunkirk Power LLC, tax exempt bonds, due 2042

Dunkirk Power LLC, tax exempt bonds, due 2042

Fort Bend County, tax-exempt bonds, due 2038 and 2042

Fort Bend County, tax-exempt bonds, due 2038 and 2042

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2017

GenOn senior notes, due 2017

GenOn senior notes, due 2017

GenOn senior notes, due 2017

GenOn senior notes, due 2017

GenOn senior notes, due 2018

GenOn senior notes, due 2018

GenOn senior notes, due 2018

GenOn senior notes, due 2018

GenOn senior notes, due 2018

GenOn senior notes, due 2020

GenOn senior notes, due 2020

GenOn senior notes, due 2020

GenOn senior notes, due 2020

GenOn senior notes, due 2020

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2031

GenOn Americas Generation senior notes, due 2031

GenOn Americas Generation senior notes, due 2031

GenOn Americas Generation senior notes, due 2031

GenOn Americas Generation senior notes, due 2031

NRG Marsh Landing term loan, due 2017 and 2023

NRG Marsh Landing term loan, due 2017 and 2023

NRG Marsh Landing term loan, due 2017 and 2023

NRG Marsh Landing term loan, due 2017 and 2023

NRG Marsh Landing term loan, due 2017 and 2023

NRG Marsh Landing term loan, due 2017 and 2023

CVSR - High Plains Ranch II LLC, due 2014 and 2037

CVSR - High Plains Ranch II LLC, due 2014 and 2037

CVSR - High Plains Ranch II LLC, due 2014 and 2037

CVSR - High Plains Ranch II LLC, due 2014 and 2037

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

Agua Caliente Solar, LLC, due 2037

Agua Caliente Solar, LLC, due 2037

Agua Caliente Solar, LLC, due 2037

Agua Caliente Solar, LLC, due 2037

Ivanpah Financing, due 2014 and 2038

Ivanpah Financing, due 2014 and 2038

Ivanpah Financing, due 2014 and 2038

South Trent Wind LLC, due 2020

South Trent Wind LLC, due 2020

South Trent Wind LLC, due 2020

South Trent Wind LLC, due 2020

South Trent Wind LLC, due 2020

South Trent Wind LLC, due 2020

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025

NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Borrego I LLC, due 2024 and 2038

NRG Solar Borrego I LLC, due 2024 and 2038

NRG Solar Blythe LLC Credit Agreement Due 2028 [Member]

NRG Solar Avra Valley LLC

NRG Solar Avra Valley LLC

NRG Solar Avra Valley LLC

NRG Solar Avra Valley LLC

TA - High Desert LLC, due 2014, 2023 and 2033

TA - High Desert LLC, due 2014, 2023 and 2033

TA - High Desert LLC, due 2014, 2023 and 2033

TA - High Desert LLC, due 2014, 2023 and 2033

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

Other

Other

Chalk Point capital lease, due 2015

Chalk Point capital lease, due 2015

Other (capital leases)

Other (capital leases)

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Term Loan Facility

Term Loan Facility

Term Loan Facility

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Current

Current

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Cash Grant Loan

Term Loan Facility

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Term Loan Facility

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Bridge Loan

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Bridge Loan

Bridge Loan

Term Loan Facility

Term Loan Facility

Non Recourse Debt

Non Recourse Debt

Minimum

Minimum

Maximum

Maximum

Minimum

Minimum

Maximum

Maximum

Minimum

Minimum

Maximum

Maximum

Minimum

Minimum

Maximum

Maximum

Minimum

Maximum

Debt Instrument

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Redemption Price, Percentage

'

'

'

'

'

'

114.18%

'

'

'

'

'

'

111.70%

'

'

113.08%

'

'

'

'

'

'

'

'

'

'

99.50%

'

'

'

'

'

'

'

'

106.78%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt

$16,804

$15,866

$8,087

$7,818

$8,717

$8,048

'

$1,130

$1,200

$800

$800

'

'

'

$602

$693

'

$1,062

$1,100

$1,128

$1,128

$990

$990

'

'

$2,002

$1,573

'

'

'

$247

$247

$59

$59

$67

$28

'

'

'

'

$0

$617

'

'

'

$782

$800

'

'

'

$780

$801

'

'

'

$621

$631

'

'

'

$503

$509

'

'

'

$435

$437

$473

$390

'

'

'

'

'

'

$1,104

$786

'

$512

$350

'

'

'

'

'

$878

$878

$640

'

$1,575

$1,437

$69

$72

'

'

'

'

'

'

'

'

'

$154

$173

$127

$137

$221

$2

'

'

'

'

'

'

$78

$0

'

'

$63

$66

'

$80

$82

$0

$22

$58

$59

$0

'

'

$21

'

$38

'

$204

$200

'

'

'

'

Capital Lease Obligations

13

17

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10

14

3

3

Subtotal

16,817

15,883

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Less current maturities

1,050

147

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt and capital leases

15,767

15,736

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage (as a percent)

'

'

'

'

'

'

'

7.63%

7.63%

7.63%

7.63%

'

'

'

8.50%

8.50%

'

8.25%

8.25%

7.88%

7.88%

6.63%

6.63%

'

'

'

'

'

'

'

'

'

5.88%

5.88%

4.75%

4.75%

'

'

'

'

7.63%

7.63%

'

'

'

7.88%

7.88%

'

'

'

9.50%

9.50%

'

'

'

9.88%

9.88%

'

'

'

8.50%

8.50%

'

'

'

9.13%

9.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.65%

'

'

'

'

'

'

5.15%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.19%

8.19%

'

'

Variable rate basis for debt instruments

'3 month LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'LIBOR

'

'LIBOR

'LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'LIBOR

'

'

'

'

'U.S. Treasury

'

'

'

'LIBOR

'LIBOR

'LIBOR

'

'

'

'

'U.S. Treasury

'

'

'

'U.S. Treasury

'

'

'LIBOR

'LIBOR

'

'

'

'

'

'

'

'

'

'LIBOR

'LIBOR

'

'

'LIBOR

'LIBOR

'

'

'

'

'1 month LIBOR

'LIBOR

'LIBOR

'

'LIBOR

'LIBOR

'

'LIBOR

'LIBOR

'LIBOR

'

'

'1 month LIBOR

'LIBOR

'

'

'

'

'1 month LIBOR

'1 month LIBOR

'3 month LIBOR

'3 month LIBOR

'

'

'

'

'

'

Debt Instrument, Unamortized Discount Relating to Current Maturities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate over variable rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.00%

3.00%

'

2.50%

2.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.50%

2.50%

2.75%

2.75%

'

0.38%

'

'

'

'

'

2.25%

2.25%

2.75%

2.75%

'

0.38%

'

'

0.38%

'

'

'

'

2.50%

2.50%

2.63%

2.63%

'

'

'

'

'

1.07%

1.07%

'

'

'

'

2.25%

2.25%

2.50%

2.50%

2.25%

2.50%

2.50%

'

'

'

2.25%

2.25%

2.25%

2.50%

'

'

'

'

'

'

2.00%

2.63%

2.00%

'

2.63%

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage, low end of the range (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.38%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.61%

'

'

'

'

'

'

'

'

'

'

2.40%

2.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.95%

5.95%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage, high end of the range (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.64%

'

'

'

'

'

'

'

'

'

'

3.26%

3.26%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.31%

7.31%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized discount on debt instruments

'

'

'

'

'

'

'

'

'

'

'

5

7

'

'

'

'

'

'

'

'

'

'

5

3

'

'

4

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11

[1]

15

[1]

'

4

[1]

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized premium on debt instruments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

[2]

42

[2]

'

'

'

58

[2]

75

[2]

75

'

'

104

[2]

126

[2]

127

'

'

71

[2]

81

[2]

82

'

'

53

[2]

59

[2]

60

'

'

35

[2]

37

[2]

37

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total premium/(discount)

$300

$395

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$43

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Discounts of $4 million and $5 million are related to current maturities in 2013 and 2012, respectively.

[2]

Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition, as described further in Note 3, Business Acquisitions and Dispositions.

Debt_and_Capital_Leases_NRG_Re

Debt and Capital Leases (NRG Recourse Debt) (Details 2) (USD $)

12 Months Ended

12 Months Ended

3 Months Ended

0 Months Ended

12 Months Ended

2 Months Ended

0 Months Ended

2 Months Ended

2 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

2 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

4 Months Ended

7 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

7 Months Ended

12 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Mar. 31, 2014

Jan. 27, 2014

Jan. 27, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Feb. 27, 2013

Dec. 31, 2013

Dec. 31, 2012

Jan. 27, 2014

Feb. 27, 2013

Dec. 31, 2013

Dec. 31, 2012

Feb. 27, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jan. 27, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Sep. 24, 2012

Feb. 27, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Oct. 18, 2012

3-May-12

Dec. 31, 2013

Oct. 18, 2012

Jun. 04, 2013

Jun. 30, 2013

Jun. 04, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 04, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

31-May-09

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Senior Credit Facility, due 2011

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Term Loan Facility

Term Loan Facility

Term Loan Facility

Term Loan Facility

Term Loan Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Redemption Period, prior to June 15, 2014

Redemption Period, June 15, 2014 to June 14, 2015

Redemption Period, June 15, 2015 to June 14, 2016

Redemption Period, June 15, 2016 to June 14, 2017

Redemption Period, June 15, 2017 and thereafter

Redemption Period, prior to September 1, 2015

Redemption Period, on or after September 1, 2015

Redemption Period, on or after September 1, 2016

Redemption Period, on or after September 1, 2017

Redemption Period, September 1, 2018 and thereafter

Redemption Period, prior to May 15, 2014

Redemption Period, May 15, 2014 to May 14, 2015

Redemption Period, May 15, 2015 to May 14, 2016

Redemption Period, May 15, 2016 and thereafter

Redemption Period, prior to May 15, 2016

Redemption Period, May 15, 2017 to May 14, 2018

Redemption Period, May 15, 2016 to May 14, 2017

Redemption Period, May 15, 2018 to May 14, 2019

Redemption Period, May 15, 2019 and thereafter

Redemption Period, prior to September 15, 2015

Redemption Period, prior to September 15, 2017

Redemption Period, September 15, 2017 to September 14, 2018

Redemption Period, September 15, 2018 to September 14, 2019

Redemption Period, September 15, 2019 to September 14, 2020

Redemption Period, September 15, 2020 and thereafter

Interest Rate Swap

Subsequent Event

Senior notes, due 2022

Senior notes, due 2022

Senior notes, due 2017

Senior notes, due 2014

Senior notes, due 2016

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

Senior notes, due 2020

Senior notes, due 2020

Senior notes, due 2020

Senior notes, due 2018

Senior notes, due 2018

Senior notes, due 2018

7.625% Senior notes, due 2019

7.625% Senior notes, due 2019

7.625% Senior notes, due 2019

Senior notes, due 2021

Senior notes, due 2021

Senior notes, due 2023

Senior notes, due 2023

Senior notes, due 2023

NRG Senior Notes Repurchased in Q1 2013

NRG Senior Notes Repurchased in Q1 2013

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Fort Bend County Tranche A Bonds [Member]

Fort Bend County Tranche A Bonds [Member]

Fort Bend County Tranche A Bonds [Member]

Fort Bend County Tranche B Bonds [Member]

Fort Bend County Tranche B Bonds [Member]

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Senior Credit Facility, due 2018

Recourse Debt

Recourse Debt

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

Recourse Debt

Senior notes, due 2020

Senior notes, due 2020

Senior notes, due 2020

Senior notes, due 2020

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Senior notes, due 2021

Recourse Debt

Senior notes, due 2021

Senior notes, due 2021

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

8.50% Senior notes, due 2019

8.50% Senior notes, due 2019

Senior notes, due 2020

7.625% Senior notes, due 2019

7.625% Senior notes, due 2019

7.625% Senior notes, due 2019

7.625% Senior notes, due 2019

7.625% Senior notes, due 2019

Senior notes, due 2021

Senior notes, due 2023

Senior notes, due 2023

Senior notes, due 2023

Senior notes, due 2023

Senior notes, due 2023

Senior notes, due 2023

Debt Instrument

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Issuance of Senior Long-term Debt

'

'

'

'

'

'

'

'

'

'

$1,100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$450,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage (as a percent)

'

'

'

'

'

'

'

'

'

'

'

6.25%

7.38%

'

'

'

8.50%

8.50%

'

'

8.25%

8.25%

'

7.63%

7.63%

7.63%

7.63%

'

7.88%

7.88%

6.63%

6.63%

'

'

'

'

'

'

4.75%

'

'

4.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Issuance of Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

978,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Senior Debt

'

'

'

'

'

'

'

'

'

'

'

'

1,100,000,000

1,200,000,000

2,400,000,000

104,000,000

'

'

308,000,000

42,000,000

'

'

80,000,000

'

'

'

'

91,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Redemption Price, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

104.02%

102.01%

103.87%

111.70%

'

'

106.99%

113.08%

'

'

114.18%

'

'

'

'

105.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

99.50%

'

'

'

'

'

'

'

'

104.25%

102.83%

101.42%

100.00%

'

104.13%

102.75%

101.38%

100.00%

'

103.81%

101.91%

100.00%

'

102.63%

103.94%

101.31%

100.00%

'

'

103.31%

102.21%

101.10%

100.00%

'

Loss on debt extinguishment

50,000,000

51,000,000

175,000,000

'

'

'

'

-32,000,000

'

33,000,000

'

'

51,000,000

28,000,000

115,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

28,000,000

'

'

'

'

'

'

'

'

7,000,000

'

'

'

'

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Call Feature

'

'

'

'

'

'

'

'

'Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Extinguishment of Debt, Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Redemption, Description

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'Prior to maturity, NRG may redeem all or a portion of the 2018 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note or (ii) the excess of the present value of the principal amount at maturity plus all required interest payments due on the note through the maturity date discounted at a Treasury rate plus 0.50%.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 104.25% of the note, plus interest payments due on the note from the date of redemption through June 15, 2014, discounted at a Treasury rate plus 0.50%.

'

'

'

'

'Prior to September 1, 2015, NRG may redeem all or a portion of the 2020 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the excess of the principal amount of the note over the following: the present value of 104.125% of the note, plus interest payments due on the note from the date of redemption through September 1, 2015, discounted at a Treasury rate plus 0.50%.

'

'

'

'

'Prior to May 15, 2014, NRG may redeem up to 35% of the aggregate principal amount of the 7.625% 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.625% of the principal amount. Prior to May 15, 2014, NRG may redeem all or a portion of the 7.625% 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.813% of the note, plus interest payments due on the note from the date of redemption through May 15, 2014, discounted at a Treasury rate plus 0.50%.

'

'

'

'Prior to May 15, 2016, NRG may redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.875% of the principal amount. Prior to May 15, 2016, NRG may redeem all or a portion of the 2021 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.938% of the note, plus interest payments due on the note from the date of redemption through May 15, 2016, discounted at a Treasury rate plus 0.50%.

'

'

'

'

'Prior to September 15, 2015, NRG may redeem up to 35% of the aggregate principal amount of the 2023 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 106.625% of the principal amount.

'Prior to September 15, 2017, NRG may redeem all or a portion of the 2023 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on the note from the date of redemption through September 15, 2017, discounted at a Treasury rate plus 0.50%.

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

990,000,000

'

'

'

'

'

'

54,000,000

'

73,000,000

407,000,000

'

407,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Description of Variable Rate Basis

'3 month LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'LIBOR

'

'

'

'

'

'

'

'LIBOR

'LIBOR

'

'

'

'LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 month LIBOR

Debt Instrument, Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.00%

3.00%

'

'

'

'

'

'

'

2.50%

2.00%

'

'

'

2.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchased Face Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

407,000,000

'

407,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Issuance Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,000,000

'

'

'

'

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized discount on debt instruments

'

'

'

5,000,000

7,000,000

5,000,000

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,000,000

'

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Periodic Payment As Percentage Of Original Principal Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Credit Facility, Maximum Borrowing Capacity, Amendment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

211,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of Credit Outstanding, Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Remaining Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of Credit Commitment Fees

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Notional Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

900,000,000

Proceeds from Issuance of Secured Tax Exempt Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$54,000,000

'

'

$12,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt_and_Capital_Leases_NRG_No

Debt and Capital Leases (NRG Non-Recourse Debt) (Details 3) (USD $)

12 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

1 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Aug. 30, 2012

Dec. 31, 2013

Mar. 16, 2012

Jun. 30, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 14, 2012

Sep. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2011

Aug. 23, 2011

Aug. 31, 2011

Dec. 31, 2013

Aug. 23, 2011

Dec. 31, 2013

Aug. 23, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Aug. 31, 2011

Dec. 31, 2013

Aug. 05, 2011

Apr. 30, 2011

Dec. 31, 2013

Apr. 05, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2002

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Oct. 31, 2010

Oct. 31, 2010

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Mar. 31, 2013

Aug. 30, 2012

Dec. 31, 2013

Jan. 15, 2013

Mar. 16, 2012

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Oct. 18, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

31-May-13

Dec. 31, 2013

Oct. 31, 2010

Oct. 31, 2010

Oct. 31, 2010

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2011

Nov. 17, 2011

31-May-09

MW

NRG Solar Avra Valley LLC

NRG Solar Avra Valley LLC

Solar Partners I Due 2014 [Member]

NRG Solar Alpine LLC, due 2014 and 2022

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2018

GenOn senior notes, due 2018

GenOn senior notes, due 2018

GenOn senior notes, due 2020

GenOn senior notes, due 2020

GenOn senior notes, due 2020

GenOn senior notes, due 2017

GenOn senior notes, due 2017

GenOn senior notes, due 2017

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2031

GenOn Americas Generation senior notes, due 2031

GenOn Americas Generation senior notes, due 2031

CVSR - High Plains Ranch II LLC, due 2014 and 2037

CVSR - High Plains Ranch II LLC, due 2014 and 2037

CVSR - High Plains Ranch II LLC, due 2014 and 2037

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

West Holdings Credit Agreement Tranche A [Member]

West Holdings Credit Agreement Tranche A [Member]

West Holdings Credit Agreement Tranche A [Member]

West Holdings Credit Agreement Tranche B [Member]

West Holdings Credit Agreement Tranche B [Member]

West Holdings PPA [Member]

West Holding Collateral Agent [Member]

West Holdings Working Capital Facility [Member]

Agua Caliente Solar, LLC, due 2037

Agua Caliente Solar, LLC, due 2037

Agua Caliente Solar, LLC, due 2037

Ivanpah Financing, due 2014 and 2038

Ivanpah Financing, due 2014 and 2038

Ivanpah Financing, due 2014 and 2038

Solar Partners I Due 2033 [Member]

Solar Partners II Due 2014 [Member]

Solar Partners II Due 2038 [Member]

Solar Partners Due 2014 [Member]

Solar Partners VIII Due 2038 [Member]

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

Redemption Period From October 15, 2015 to October 14, 2016 [Member]

Redemption Period Prior To 15 January 2018 [Member]

Redemption Period Prior to October 15, 2015 [Member]

Redemption Period Prior to Maturity [Member]

Redemption Period Prior to Maturity [Member]

Redemption Period Prior to Maturity [Member]

Redemption Period From October 15, 2016 to October 14, 2017 [Member]

Redemption Period From October 15, 2017 to October 14, 2018 [Member]

Redemption Period Beginning with October 15, 2018 [Member]

GenOn Energy

Kansas South [Member]

GenOn Marsh Landing

GenOn Marsh Landing

TA - High Desert LLC [Member]

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Term Loan Facility

Term Loan Facility

Term Loan Facility

Term Loan Facility

Term Loan Facility

Term Loan Facility

Bridge Loan

Bridge Loan

Bridge Loan

Cash Grant Loan

Cash Grant Loan

Cash Grant Loan

Cash Grant Loan

Construction Loans [Member]

Construction Loans [Member]

Fixed Rate Notes [Member]

Floating Rate Notes [Member]

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Recourse Debt

Recourse Debt

Recourse Debt

Recourse Debt

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Letter of Credit [Member]

Credit Facility [Domain]

Credit Facility [Domain]

Support Debt Service Requirements [Member]

Support Collateral Requirements [Member]

Minimum

Minimum

Minimum

Minimum

Minimum

Minimum

Maximum

Maximum

Maximum

Maximum

Maximum

Maximum

Interest Rate Swap

Interest Rate Swap

Interest Rate Swap

GenOn senior notes, due 2020

GenOn senior notes, due 2018

GenOn senior notes, due 2020

GenOn senior notes, due 2017

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2031

GenOn senior notes, due 2020

GenOn senior notes, due 2020

GenOn senior notes, due 2020

MW

Marsh Landing Term Loan Due 2017 [Member]

Marsh Landing Term Loan Due 2023 [Member]

MW

NRG Solar Avra Valley LLC

NRG Solar Avra Valley LLC

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

GenOn senior notes, due 2014

GenOn senior notes, due 2014

GenOn senior notes, due 2018

GenOn senior notes, due 2018

GenOn senior notes, due 2020

GenOn senior notes, due 2020

GenOn senior notes, due 2017

GenOn senior notes, due 2017

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2021

GenOn Americas Generation senior notes, due 2031

GenOn Americas Generation senior notes, due 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

TA - High Desert LLC, due 2014, 2023 and 2033

TA - High Desert LLC, due 2014, 2023 and 2033

TA - High Desert LLC, due 2014, 2023 and 2033

CVSR - High Plains Ranch II LLC, due 2014 and 2037

CVSR - High Plains Ranch II LLC, due 2014 and 2037

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

Agua Caliente Solar, LLC, due 2037

Agua Caliente Solar, LLC, due 2037

Ivanpah Financing, due 2014 and 2038

Ivanpah Financing, due 2014 and 2038

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Peaker Finance Co. LLC, bonds, due 2019

NRG Solar Avra Valley LLC

NRG Solar Avra Valley LLC

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Solar Kansas South LLC, due 2014 and 2031

TA - High Desert LLC, due 2014, 2023 and 2033

NRG Solar Avra Valley LLC

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Avra Valley LLC

NRG Solar Alpine LLC, due 2014 and 2022

TA - High Desert LLC, due 2014, 2023 and 2033

TA - High Desert LLC, due 2014, 2023 and 2033

TA - High Desert LLC, due 2014, 2023 and 2033

TA - High Desert LLC, due 2014, 2023 and 2033

NRG Yield, Inc.

Fort Bend County Tranche B Bonds [Member]

Fort Bend County Tranche B Bonds [Member]

NRG Solar Avra Valley LLC

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Kansas South LLC, due 2014 and 2031

NRG Repowering Holdings LLC Credit Facility [Member]

GenOn Marsh Landing

GenOn Marsh Landing

GenOn Marsh Landing

GenOn Marsh Landing

GenOn Marsh Landing

West Holdings Credit Agreement Tranche B [Member]

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

West Holdings Credit Agreement Tranche B [Member]

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

CVSR - High Plains Ranch II LLC, due 2014 and 2037

CVSR - High Plains Ranch II LLC, due 2014 and 2037

Recourse Debt

Letter of Credit [Member]

Letter of Credit [Member]

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Kansas South LLC, due 2014 and 2031

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Alpine LLC, due 2014 and 2022

NRG Solar Kansas South LLC, due 2014 and 2031

NRG West Holdings LLC, term loan, due 2023

NRG West Holdings LLC, term loan, due 2023

Debt Instrument

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Issuance of Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$325,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchased Face Amount

'

'

'

'

'

'

'

575,000,000

575,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

159,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000,000

'

540,000,000

'

'

480,000,000

'

60,000,000

90,000,000

48,000,000

10,000,000

'

'

967,000,000

'

1,627,000,000

1,600,000,000

392,000,000

132,000,000

387,000,000

117,000,000

440,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,000,000

60,000,000

'

'

'

'

4,000,000

37,000,000

'

'

'

'

650,000,000

50,000,000

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters Of Credit, Availability Fee, Percentage Of Applicable Margin

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Redemption Price, Percentage

'

'

'

'

'

'

'

106.78%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

104.94%

'

'

'

'

'

103.29%

101.65%

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss on debt extinguishment

-50,000,000

-51,000,000

-175,000,000

'

'

'

'

'

-11,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt

16,804,000,000

15,866,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

480,000,000

'

32,000,000

'

'

'

'

'

878,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,717,000,000

8,048,000,000

63,000,000

66,000,000

221,000,000

2,000,000

0

617,000,000

780,000,000

801,000,000

621,000,000

631,000,000

782,000,000

800,000,000

503,000,000

509,000,000

435,000,000

437,000,000

58,000,000

59,000,000

0

80,000,000

82,000,000

0

1,104,000,000

786,000,000

512,000,000

350,000,000

878,000,000

640,000,000

1,575,000,000

1,437,000,000

154,000,000

173,000,000

'

'

'

'

38,000,000

'

21,000,000

'

22,000,000

'

'

'

'

'

'

53,000,000

7,000,000

'

'

'

8,087,000,000

7,818,000,000

'

'

'

'

'

'

'

473,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.63%

7.63%

9.50%

9.50%

9.88%

9.88%

7.88%

7.88%

8.50%

8.50%

9.13%

9.13%

'

'

'

5.15%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.15%

'

'

'

'

'

'

'

4.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Construction Loan, Noncurrent

'

'

'

63,000,000

66,000,000

159,000,000

166,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,575,000,000

'

371,000,000

132,000,000

377,000,000

116,000,000

420,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,104,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

159,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Weighted Average Interest Rate

'

'

'

'

'

1.68%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.81%

1.61%

3.13%

2.00%

3.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

'

'

'

'

'

575,000,000

'

'

675,000,000

'

'

550,000,000

'

'

725,000,000

'

'

450,000,000

'

'

400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

155,000,000

345,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,000,000

'

63,000,000

68,000,000

'

'

'

'

'

'

'

'

'

'

73,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Fair Value

'

'

'

'

'

'

'

'

'

'

'

618,000,000

'

'

802,000,000

'

'

632,000,000

'

'

800,000,000

'

'

510,000,000

'

'

437,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Unamortized Premium

'

'

'

'

'

'

'

'

'

0

[1]

42,000,000

[1]

'

104,000,000

[1]

126,000,000

[1]

127,000,000

71,000,000

[1]

81,000,000

[1]

82,000,000

58,000,000

[1]

75,000,000

[1]

75,000,000

53,000,000

[1]

59,000,000

[1]

60,000,000

35,000,000

[1]

37,000,000

[1]

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation capacity (in MW)

45,881

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20

'

'

20

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total premium/(discount)

300,000,000

395,000,000

'

'

'

'

'

'

'

'

'

43,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted Payments Limit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Restricted Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Redemption, Description

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'Prior to maturity, GenOn may redeem the senior notes due 2018, in whole or in part, at a redemption price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note.

'Prior to October 15, 2015, GenOn may redeem the senior notes due 2020, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note.

'Prior to maturity, GenOn may redeem all or a part of the GenOn Senior Notes due 2017 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note

'Prior to maturity, GenOn Americas Generation may redeem all or a part of the senior notes due 2021 and 2031 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) the discounted present value of the then-remaining scheduled payments of principal and interest on the outstanding notes, discounted at a Treasury rate plus 0.375%, less the unpaid principal amount; and (ii) zero.

'Prior to maturity, GenOn Americas Generation may redeem all or a part of the senior notes due 2021 and 2031 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) the discounted present value of the then-remaining scheduled payments of principal and interest on the outstanding notes, discounted at a Treasury rate plus 0.375%, less the unpaid principal amount; and (ii) zero.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Period Payment is Due After Receipt of Cash Grant

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 days

'

'10 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Description of Variable Rate Basis

'3 month LIBOR

'

'

'LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'U.S. Treasury

'

'

'LIBOR

'

'

'

'

'

'

'

'

'

'U.S. Treasury

'

'

'U.S. Treasury

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'LIBOR

'LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'

'

'LIBOR

'

'

'

'

'LIBOR

'LIBOR

'

'

'

'

'LIBOR

'LIBOR

'LIBOR

'

'

'LIBOR

'3 month LIBOR

'3 month LIBOR

'1 month LIBOR

'1 month LIBOR

'1 month LIBOR

'

'1 month LIBOR

'

'

'

'LIBOR

'

'3 month LIBOR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 month LIBOR

Debt Instrument, Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.38%

'

'

'

'

'

'

'

'

'

'

'

'

0.38%

'

0.38%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.25%

2.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.50%

'

'

'

'

'

'

'

'

'

'

1.07%

1.07%

2.25%

'

'

2.50%

2.63%

'

2.00%

'

'

'

2.25%

'

'

2.25%

2.50%

'

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.25%

2.25%

2.00%

2.25%

2.25%

'

2.50%

2.50%

2.63%

2.75%

2.75%

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity Available for Issuance of Letters of Credit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Incremental Escalation On Basis Spread, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25%

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.13%

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

Debt Instrument, Escalation Percent of Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Escalation Period of Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'4 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of Credit Outstanding, Amount

'

'

'

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

33,000,000

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

4,000,000

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,000,000

'

'

'

'

'

'

'

37,000,000

4,000,000

'

24,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Issued Letters of Credit Returned, Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

82,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Notional Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

686,000,000

900,000,000

Percentage of Term Loan Entered into Interest Rate Swap

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

Number of Scheduled Settlement Dates for Swaption Maturity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7

'

'

Line of Credit Facility, Amount Outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

165,000,000

165,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Letters of Credit, Issued Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

36,000,000

36,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Contributions from Parent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

32,000,000

19,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Issuance of Secured Tax Exempt Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of Restricted Net Assets for Consolidated and Unconsolidated Subsidiaries

$3,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition, as described further in Note 3, Business Acquisitions and Dispositions.

Debt_and_Capital_Leases_Intere

Debt and Capital Leases (Interest Rate Swaps) (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Debt Instrument	'
Variable rate basis for debt instruments	'3 month LIBOR
NRG Peaker Finance Co. LLC	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	100.00%
Variable rate basis for debt instruments	'3 month LIBOR
Debt instrument, interest rate over variable rate (as a percent)	1.07%
NRG Peaker Finance Co. LLC | Interest Rate Swap	'
Debt Instrument	'
Derivative, Fixed Interest Rate	6.67%
Derivative, Notional Amount	165
NRG West Holdings LLC	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Variable rate basis for debt instruments	'3-mo. LIBOR
NRG West Holdings LLC | Interest Rate Swap	'
Debt Instrument	'
Derivative, Fixed Interest Rate	2.42%
Derivative, Notional Amount	405
NRG Solar Roadrunner LLC	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Variable rate basis for debt instruments	'3-mo. LIBOR
NRG Solar Roadrunner LLC | Interest Rate Swap	'
Debt Instrument	'
Derivative, Fixed Interest Rate	4.31%
Derivative, Notional Amount	33
NRG Solar Alpine LLC	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Variable rate basis for debt instruments	'3-mo. LIBOR
NRG Solar Alpine LLC | Interest Rate Swap	'
Debt Instrument	'
Derivative, Fixed Interest Rate	2.74%
Derivative, Notional Amount	135
NRG Solar Avra Valley LLC	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	90.00%
Variable rate basis for debt instruments	'3-mo. LIBOR
NRG Solar Avra Valley LLC | Interest Rate Swap	'
Debt Instrument	'
Derivative, Fixed Interest Rate	2.33%
Derivative, Notional Amount	56
Maturity - June 14, 2020 | South Trent Wind LLC	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Variable rate basis for debt instruments	'3-mo. LIBOR
Maturity - June 14, 2020 | South Trent Wind LLC | Interest Rate Swap	'
Debt Instrument	'
Derivative, Fixed Interest Rate	3.27%
Derivative, Notional Amount	51
Maturity - June 14, 2028 | South Trent Wind LLC	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Variable rate basis for debt instruments	'3-mo. LIBOR
Maturity - June 14, 2028 | South Trent Wind LLC | Interest Rate Swap	'
Debt Instrument	'
Derivative, Fixed Interest Rate	4.95%
Derivative, Notional Amount	21
Maturity - June 30, 2023 | GenOn Marsh Landing	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Variable rate basis for debt instruments	'3-mo. LIBOR
Maturity - June 30, 2023 | GenOn Marsh Landing | Interest Rate Swap	'
Debt Instrument	'
Derivative, Fixed Interest Rate	3.24%
Derivative, Notional Amount	472
Other	'
Debt Instrument	'
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Other | Interest Rate Swap	'
Debt Instrument	'
Derivative, Notional Amount	104

Debt_and_Capital_Leases_Consol

Debt and Capital Leases (Consolidated Annual Maturities) (Details 5) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Debt Disclosure [Abstract]	'	'
Annual maturities, 2014	$1,045	'
Annual maturities, 2015	254	'
Annual maturities, 2016	270	'
Annual maturities, 2017	1,034	'
Annual maturities, 2018	4,035	'
Annual maturities, Thereafter	10,166	'
Total	$16,804	$15,866

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligation, Revision of Estimate	$77
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'
Balance at the beginning of the period	646
Additions	29
Spending for current obligations	5
Accretion — Expense	19
Accretion — Nuclear decommissioning	17
Balance at the ending of the period	$629

Benefit_Plans_and_Other_Postre2

Benefit Plans and Other Postretirement Benefits (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
		Pension Benefits	Pension Benefits	Pension Benefits	Other Postretirement Benefits	Other Postretirement Benefits	Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits	'	'	'	'	'	'	'
Defined Benefit Plan, Curtailments	'	$1,000,000	$0	'	$0	$0	'
Expected contribution to the Company's pension plans in 2014	'	78,000,000	'	'	'	'	'
Annual periodic pension cost	'	'	'	'	'	'	'
Service cost benefits earned	'	30,000,000	14,000,000	14,000,000	4,000,000	2,000,000	2,000,000
Interest cost on benefit obligation	'	47,000,000	23,000,000	21,000,000	9,000,000	6,000,000	6,000,000
Expected return on plan assets	'	-55,000,000	-23,000,000	-21,000,000	'	'	'
Amortization of unrecognized net loss	'	9,000,000	4,000,000	0	0	1,000,000	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	'	1,000,000	0	'	'	'	'
Net periodic benefit cost	'	30,000,000	18,000,000	14,000,000	13,000,000	9,000,000	8,000,000
Pension and other post retirement benefit obligations	'	'	'	'	'	'	'
Benefit obligation at January 1	'	1,147,000,000	'	456,000,000	220,000,000	'	122,000,000
Obligations assumed in the GenOn acquisition	'	0	596,000,000	'	0	87,000,000	'
Service cost	'	30,000,000	14,000,000	14,000,000	4,000,000	2,000,000	2,000,000
Interest cost	'	47,000,000	23,000,000	21,000,000	9,000,000	6,000,000	6,000,000
Plan amendments	'	5,000,000	0	'	-4,000,000	-1,000,000	'
Actuarial (gain)/loss	'	-125,000,000	75,000,000	'	-29,000,000	6,000,000	'
Employee and retiree contributions	'	0	0	'	2,000,000	1,000,000	'
Benefit payments	'	43,000,000	-17,000,000	'	11,000,000	-3,000,000	'
Benefit obligation at December 31	'	1,060,000,000	1,147,000,000	'	191,000,000	220,000,000	'
Fair value of plan assets for pension and other post retirement benefit	'	'	'	'	'	'	'
Fair value of plan assets at January 1	'	757,000,000	'	308,000,000	0	'	0
Assets acquired in the GenOn acquisition	'	0	402,000,000	'	0	0	'
Actual return on plan assets	'	116,000,000	41,000,000	'	0	0	'
Employee contributions	'	0	0	'	2,000,000	1,000,000	'
Employer contributions	'	50,000,000	23,000,000	'	9,000,000	2,000,000	'
Benefit payments	'	43,000,000	-17,000,000	'	11,000,000	-3,000,000	'
Fair value of plan assets at December 31	'	880,000,000	757,000,000	'	0	0	'
Funded status at December 31 — excess of obligation over assets	'	-180,000,000	-390,000,000	'	-191,000,000	-220,000,000	'
Litigation Settlement, Amount	$12,000,000	'	'	'	'	'	'

Benefit_Plans_and_Other_Postre3

Benefit Plans and Other Postretirement Benefits (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits	'	'	'	'
Amounts recognized in balance sheet	'	'	'	'
Current liabilities	$12	$1	'	'
Non-current liabilities	166	389	'	'
Amounts recognized in accumulated OCI	'	'	'	'
Unrecognized (gain)/loss	57	-140	'	'
Prior service cost/(credit)	4	-2	'	'
Other changes in plan assets and benefit obligations recognized in other comprehensive income	'	'	'	'
Unrecognized (gain)/loss	-188	56	'	'
Amortization of net actuarial gain	-9	-4	0	'
Prior service credit	5	0	'	'
Defined Benefit Plan, Curtailments	1	0	'	'
Total recognized in other comprehensive loss	191	-52	'	'
Total recognized in net periodic pension cost and other comprehensive income	-161	71	'	'
Estimated unrecognized loss for NRG's pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year	5	'	'	'
Significant components of NRG's domestic pension plan	'	'	'	'
Projected benefit obligation	1,060	1,147	'	456
Accumulated benefit obligation	967	1,024	'	'
Fair value of plan assets	880	757	'	308
Other Postretirement Benefits	'	'	'	'
Amounts recognized in balance sheet	'	'	'	'
Current liabilities	9	9	'	'
Non-current liabilities	182	211	'	'
Amounts recognized in accumulated OCI	'	'	'	'
Unrecognized (gain)/loss	12	-17	'	'
Prior service cost/(credit)	-6	-2	'	'
Other changes in plan assets and benefit obligations recognized in other comprehensive income	'	'	'	'
Unrecognized (gain)/loss	-29	7	'	'
Amortization of net actuarial gain	0	-1	0	'
Prior service credit	-4	-1	'	'
Defined Benefit Plan, Curtailments	0	0	'	'
Total recognized in other comprehensive loss	33	-5	'	'
Total recognized in net periodic pension cost and other comprehensive income	-20	13	'	'
Significant components of NRG's domestic pension plan	'	'	'	'
Projected benefit obligation	191	220	'	122
Fair value of plan assets	$0	$0	'	$0

Benefit_Plans_and_Other_Postre4

Benefit Plans and Other Postretirement Benefits (Details 3) (Pension Benefits, USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
In Millions, unless otherwise specified
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	$880	$757	$308
Level 1	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	2	24	'
Level 2	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	878	733	'
U.S. equity investment	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	26	'
U.S. equity investment | Level 1	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	0	'
U.S. equity investment | Level 2	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	26	'
Non-U.S. equity investment	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	68	'
Non-U.S. equity investment | Level 1	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	24	'
Non-U.S. equity investment | Level 2	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	44	'
Corporate bond investment — fixed income	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	32	'
Corporate bond investment — fixed income | Level 1	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	0	'
Corporate bond investment — fixed income | Level 2	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	'	32	'
Common/collective trust investment — U.S. equity	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	370	290	'
Common/collective trust investment — U.S. equity | Level 1	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	0	0	'
Common/collective trust investment — U.S. equity | Level 2	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	370	290	'
Common/collective trust investment — non-U.S. equity	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	212	111	'
Common/collective trust investment — non-U.S. equity | Level 1	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	0	0	'
Common/collective trust investment — non-U.S. equity | Level 2	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	212	111	'
Common/collective trust investment — fixed income	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	296	228	'
Common/collective trust investment — fixed income | Level 1	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	0	0	'
Common/collective trust investment — fixed income | Level 2	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	296	228	'
Short-term investment fund	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	2	2	'
Short-term investment fund | Level 1	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	2	0	'
Short-term investment fund | Level 2	'	'	'
Benefit Plans and Other Postretirement Benefits	'	'	'
Fair values of the Company's pension plan assets	$0	$2	'

Benefit_Plans_and_Other_Postre5

Benefit Plans and Other Postretirement Benefits (Details 4)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Minimum	'	'	'
Significant assumptions used to calculate NRG's benefit expense	'	'	'
Aon Hewitt above median yield curve discount rate (in years)	0.5	'	'
Maximum	'	'	'
Significant assumptions used to calculate NRG's benefit expense	'	'	'
Aon Hewitt above median yield curve discount rate (in years)	99	'	'
Pension Benefits	'	'	'
Significant assumptions used to calculate NRG's benefit obligations	'	'	'
Discount rate	4.99%	4.16%	'
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.65%	3.57%	'
Significant assumptions used to calculate NRG's benefit expense	'	'	'
Discount rate	4.16%	4.95%	5.47%
Expected return on plan assets	7.12%	6.96%	7.34%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.57%	4.34%	4.40%
Pension Benefits | Minimum	'	'	'
Significant assumptions used to calculate NRG's benefit expense	'	'	'
Expected return on plan assets	'	6.75%	7.25%
Pension Benefits | Maximum	'	'	'
Significant assumptions used to calculate NRG's benefit expense	'	'	'
Expected return on plan assets	'	7.50%	7.50%
Other Postretirement Benefits	'	'	'
Significant assumptions used to calculate NRG's benefit obligations	'	'	'
Discount rate	5.06%	4.31%	'
Defined Benefit Plan Obligation, Health Care Cost Trend Rate Assumed for Next Fiscal Year	'	8.00%	'
Defined Benefit Plan Obligation, Ultimate Health Care Cost Trend Rate	'	5.00%	'
Significant assumptions used to calculate NRG's benefit expense	'	'	'
Discount rate	4.31%	5.15%	5.77%
Expected return on plan assets	0.00%	'	'
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	0.00%	'	'
Other Postretirement Benefits | Minimum	'	'	'
Significant assumptions used to calculate NRG's benefit expense	'	'	'
Health care trend rate, ultimate cost trend rate	5.30%	5.00%	5.00%
Other Postretirement Benefits | Maximum	'	'	'
Significant assumptions used to calculate NRG's benefit expense	'	'	'
Health care trend rate	8.30%	8.00%	8.00%
U.S. equity | Pension Benefits | Minimum	'	'	'
Target allocations	'	'	'
Defined Benefit Plan, Target Allocation Percentage	'.385	'.385	'
U.S. equity | Pension Benefits | Maximum	'	'	'
Target allocations	'	'	'
Defined Benefit Plan, Target Allocation Percentage	'.455	'.455	'
Non-U.S. equity | Pension Benefits | Minimum	'	'	'
Target allocations	'	'	'
Defined Benefit Plan, Target Allocation Percentage	'.165	'.165	'
Non-U.S. equity | Pension Benefits | Maximum	'	'	'
Target allocations	'	'	'
Defined Benefit Plan, Target Allocation Percentage	'.28	'.28	'
U.S. fixed income | Pension Benefits | Minimum	'	'	'
Target allocations	'	'	'
Defined Benefit Plan, Target Allocation Percentage	'.3	'.3	'
U.S. fixed income | Pension Benefits | Maximum	'	'	'
Target allocations	'	'	'
Defined Benefit Plan, Target Allocation Percentage	'.45	'.45	'

Benefit_Plans_and_Other_Postre6

Benefit Plans and Other Postretirement Benefits (Details 5) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
One-percentage-point change in assumed health care cost trend rates	'		'		'
Effect on total service and interest cost components, 1-Percentage-Point Increase	$1		'		'
Effect on total service and interest cost components, 1-Percentage-Point Decrease	1		'		'
Effect on postretirement benefit obligation, 1-Percentage-Point Increase	14		'		'
Effect on postretirement benefit obligation, 1-Percentage-Point Decrease	11		'		'
Company's contributions to 401(k) plans	'		'		'
Company contributions to defined contribution plans	34	[1]	24	[1]	24	[1]
South Texas Project	'		'		'
STP Defined Benefit Plans	'		'		'
Ownership interest in STP (as a percent)	44.00%		'		'
Percentage of contribution to the retirement plan obligation reimbursed	44.00%		'		'
Amount reimbursed to STPNOC towards defined benefit plans	14		15		'
Expected reimbursement of contribution to retirement plan obligations to STPNOC in 2014	18		'		'
Pension Benefits	'		'		'
NRG's expected future benefit payments	'		'		'
Expected future benefit payments, 2014	60		'		'
Expected future benefit payments, 2015	53		'		'
Expected future benefit payments, 2016	58		'		'
Expected future benefit payments, 2017	59		'		'
Expected future benefit payments, 2018	63		'		'
Expected future benefit payments, 2019-2023	362		'		'
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP	'		'		'
Funded status — STPNOC benefit plans	-180		-390		'
Net periodic benefit costs	30		18		14
Total recognized in other comprehensive loss	191		-52		'
Pension Benefits | South Texas Project	'		'		'
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP	'		'		'
Funded status — STPNOC benefit plans	-42		-76		'
Net periodic benefit costs	11		10		'
Total recognized in other comprehensive loss	-31		14		'
Other Postretirement Benefits	'		'		'
NRG's expected future benefit payments	'		'		'
Expected future benefit payments, 2014	9		'		'
Expected future benefit payments, 2015	10		'		'
Expected future benefit payments, 2016	10		'		'
Expected future benefit payments, 2017	10		'		'
Expected future benefit payments, 2018	11		'		'
Expected future benefit payments, 2019-2023	62		'		'
Medicare prescription drug reimbursements	'		'		'
Expected Medicare prescription drug reimbursements, 2014	0		'		'
Expected Medicare prescription drug reimbursements, 2015	0		'		'
Expected Medicare prescription drug reimbursements, 2016	0		'		'
Expected Medicare prescription drug reimbursements, 2017	0		'		'
Expected Medicare prescription drug reimbursements, 2018	0		'		'
Expected Medicare prescription drug reimbursements, 2019-2023	2		'		'
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP	'		'		'
Funded status — STPNOC benefit plans	-191		-220		'
Net periodic benefit costs	13		9		8
Total recognized in other comprehensive loss	33		-5		'
Other Postretirement Benefits | South Texas Project	'		'		'
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP	'		'		'
Funded status — STPNOC benefit plans	-52		-56		'
Net periodic benefit costs	8		8		'
Total recognized in other comprehensive loss	($10)		$1		'
[1]	Includes contributions to former GenOn plans for the period of December 15, 2012 to December 31, 2012.

Capital_Structure_Details

Capital Structure (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Aug. 15, 2012

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2009

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2009

Dec. 31, 2013

Dec. 31, 2012

Preferred Stock

Long-term incentive plans

Common Stock

Common Stock

Common Stock

Common Stock

Common Stock

Treasury Stock

Treasury Stock

Treasury Stock

Treasury Stock

Plan

Plan

Capital Structure

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, shares authorized

'

10,000,000

'

'

'

10,000,000

'

'

'

10,000,000

10,000,000

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, shares authorized

'

500,000,000

'

'

'

500,000,000

'

'

'

500,000,000

500,000,000

500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

3.625% convertible perpetual preferred stock, shares issued

'

250,000

'

'

'

250,000

'

'

'

250,000

250,000

250,000

'

'

'

'

'

'

'

'

'

'

'

'

'

3.625% convertible perpetual preferred stock, shares outstanding

'

250,000

'

'

'

250,000

'

'

'

250,000

250,000

250,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Beginning balance, common shares issued

'

'

'

'

399,112,616

'

'

'

'

399,112,616

'

'

'

'

399,112,616

399,112,616

'

304,183,720

304,006,027

'

'

'

'

'

'

Beginning balance, treasury shares

'

'

'

'

-76,505,718

'

'

'

'

-76,505,718

'

'

'

'

'

'

'

'

'

-76,505,718

'

-76,664,199

-56,808,672

'

'

Beginning balance, common shares outstanding

'

'

'

'

322,606,898

'

'

'

'

322,606,898

'

'

'

'

322,606,898

322,606,898

'

227,519,521

247,197,355

'

'

'

'

'

'

Shares issued under ESPP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

71,478

130,482

158,481

120,127

'

130,482

158,481

120,127

'

'

'

Stock Repurchase Program, Authorized Amount

'

'

'

'

'

'

'

'

'

$200

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares issued from LTIP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,014,164

996,262

177,693

'

'

'

'

'

'

'

Stock Repurchased During Period, Shares

'

'

'

'

-972,292

'

'

'

'

'

'

'

'

'

'

-972,292

'

-19,975,654

'

-972,292

'

-19,975,654

'

'

'

Stock Issued through GenOn acquisition

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

93,932,634

'

'

'

'

'

'

'

'

Ending balance, common shares issued

'

401,126,780

'

'

'

399,112,616

'

'

'

401,126,780

399,112,616

'

'

'

'

401,126,780

399,112,616

'

304,006,027

'

'

'

'

'

'

Ending balance, treasury shares

'

-77,347,528

'

'

'

-76,505,718

'

'

'

-77,347,528

-76,505,718

'

'

'

'

'

'

'

'

-77,347,528

-76,505,718

'

-56,808,672

'

'

Ending balance, common shares outstanding

'

323,779,252

'

'

'

322,606,898

'

'

'

323,779,252

322,606,898

'

'

'

'

323,779,252

322,606,898

'

247,197,355

'

'

'

'

'

'

Common Stock, Shares Reserved

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock, Capital Shares Reserved for Future Issuance

'

37,121,160

'

'

'

'

'

'

'

37,121,160

'

'

16,000,000

21,121,160

'

'

'

'

'

'

'

'

'

'

'

Dividends, Common Stock [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock, Dividends, Per Share, Cash Paid

$0.09

$0.12

$0.12

$0.12

$0.09

$0.09

$0.09

$0

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends Per Common Share

'

'

'

'

'

'

'

'

'

$0.45

$0.18

$0

'

'

'

'

'

'

'

'

'

'

'

$0.48

$0.36

Common Stock, Dividends, Proposed Annual Percentage Increase

'

'

'

'

'

33.00%

'

'

'

'

33.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capital_Structure_Details_2

Capital Structure (Details 2) (USD $)	3 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Stock Purchase Plan and 2013 Capital Allocation Plan	'	'	'	'
Eligible compensation (as a percent)	'	10.00%	'	'
Exercise price as a percentage of fair value (as a percent)	'	85.00%	'	'
Treasury stock reserved for issuance under the ESPP (in shares)	'	888,388	'	'
Stock Repurchase Program, Authorized Amount	'	200	'	'
Stock Repurchased During Period, Shares	972,292	'	'	'
Stock Repurchased During Period, Value	25	'	'	'
Treasury Stock Acquired, Average Cost Per Share	25.88	'	'	'
Stock Repurchase Program, Remaining Authorized Repurchase Amount	'	175	'	'
Common Stock	'	'	'	'
Employee Stock Purchase Plan and 2013 Capital Allocation Plan	'	'	'	'
Common stock issued to employee from treasury stock (in shares)	71,478	130,482	158,481	120,127
Stock Repurchased During Period, Shares	'	972,292	'	19,975,654

Capital_Structure_Details_3

Capital Structure (Details 3) (Preferred Stock, USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Aug. 11, 2005	Aug. 11, 2015
				Forecast
				day
Capital Structure	'	'	'	'
Preferred Stock, Shares Issued	'	'	250,000	'
Dividend rate of Preferred Stock (as a percent)	3.63%	3.63%	'	'
Liquidation preference (in dollars per share)	$1,000	'	'	'
Dividends on preferred stock per share per year	$36.25	'	'	'
Preferred stock, conversion period (in days)	'	'	'	90
Convertible perpetual preferred stock, terms of conversion	'Holders tendering the 3.625% Preferred Stock for conversion shall be entitled to receive, for each share of 3.625% Preferred Stock converted, $1,000 in cash and a number of shares of NRG common stock equal in value to the product of (a) the greater of (i) the difference between the average closing share price of NRG common stock on each of the twenty consecutive scheduled trading days starting on the date thirty exchange business days immediately prior to the conversion date, or the Market Price, and $29.54 and (ii) zero, times (b) 50.77. The number of shares of NRG common stock to be delivered under the conversion feature is limited to 16,000,000 shares. If upon conversion, the Market Price is less than $19.69, then the Holder will deliver to NRG cash or a number of shares of NRG common stock equal in value to the product of (i) $19.69 minus the Market Price, times (ii) 50.77.	'	'	'
Redemption price as a percentage of liquidation preference (as a percent)	100.00%	'	'	'

Investments_Accounted_for_by_t2

Investments Accounted for by the Equity Method and Variable Interest Entities (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Apr. 30, 2009

Apr. 30, 2009

Apr. 30, 2009

Mar. 31, 2012

Apr. 30, 2009

Dec. 31, 2013

Dec. 31, 2009

Dec. 31, 2008

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

MW

GenConn Energy LLC

GenConn Energy LLC

GenConn Energy LLC

GenConn Energy LLC

GenConn Energy LLC

GenConn Energy LLC

GenConn Energy LLC

Sherbino I Wind Farm LLC

Sherbino I Wind Farm LLC

Sherbino I Wind Farm LLC

Sherbino I Wind Farm LLC

Texas Coastal Ventures, LLC

Gladstone Power Station

United States

United States

United States

United States

United States

United States

United States

Australia

generatingunit

year

GenConn Facility

GenConn Facility

GenConn Working Capital Facility

GenConn Working Capital Facility

GenConn Working Capital Facility

MW

Sherbino I Wind Farm LLC Term Loan Facility

Sherbino I Wind Farm LLC Term Loan Facility

year

MW

Avenal Solar Holdings LLC

GenConn Energy LLC

Saguaro Power Company

Sherbino I Wind Farm LLC

Texas Coastal Ventures, LLC

Sabine CoGen, LP

Sunora Energy Solutions I LLC

Gladstone Power Station

MW

Non Recourse Debt

year

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

Non Recourse Debt

facility

Investments Accounted for by the Equity Method

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Economic interest in equity method investments (as a percent)

'

'

'

50.00%

'

'

'

'

'

'

50.00%

'

'

50.00%

37.50%

50.00%

50.00%

50.00%

50.00%

50.00%

50.00%

50.00%

37.50%

Undistributed earnings by equity investment

$94

$149

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of peaking facilities to be constructed

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Power generation capacity of the peaking facility to be constructed in Connecticut (in MW)

'

'

'

190

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term of contract with Connecticut Light & Power Company (in years)

'

'

'

30

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of units reached commercial operation at the peaking generation facilities

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

453

676

'

118

'

'

'

'

'

'

'

'

'

'

188

'

'

'

'

'

'

'

'

Percentage of Project Construction Costs, Secured by Equity Method Investee

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Length of term loan facility (in years)

'

'

'

'

7

'

'

'

'

'

'

15

'

'

'

'

'

'

'

'

'

'

'

Length of revolving working capital loan and letter of credit facility (in years)

'

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum borrowing capacity under line of credit facility

'

'

'

'

'

291

'

35

48

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Amount Outstanding

'

'

'

'

'

'

'

'

'

'

'

'

114

'

'

'

'

'

'

'

'

'

'

Generation capacity (in MW)

45,881

'

'

'

'

'

'

'

'

'

150

'

'

'

1,613

'

'

'

'

'

'

'

'

Maximum exposure to loss

'

'

'

'

'

'

'

'

'

$87

'

'

'

$63

'

'

'

'

'

'

'

'

'

Term of CO2 supply agreement (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

20

'

'

'

'

'

'

'

'

'

Segment_Reporting_Details

Segment Reporting (Details) (USD $)

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

$2,795

$3,490

$2,930

$2,081

$2,063

$2,331

$2,166

$1,862

$11,295

$8,422

$9,079

Operating expenses

'

'

'

'

'

'

'

'

9,109

7,015

7,388

Depreciation and amortization

'

'

'

'

'

'

'

'

1,256

950

896

Impairment charges

'

'

'

'

'

'

'

'

459

107

160

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

128

107

0

Operating income/(loss)

-205

527

287

-266

37

86

397

-170

343

350

635

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

7

37

35

Impairment losses on investments

'

'

'

'

'

'

'

'

-99

-2

-495

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

0

296

0

Other income, net

'

'

'

'

'

'

'

'

13

19

19

Loss on debt extinguishment

'

'

'

'

'

'

'

'

-50

-51

-175

Interest expense

'

'

'

'

'

'

'

'

-848

-661

-665

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-634

-12

-646

Income tax benefit

'

'

'

'

'

'

'

'

-282

-327

-843

Net (Loss)/Income

'

'

'

'

'

'

'

'

-352

315

197

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

34

20

0

Net income/(loss) attributable to NRG Energy, Inc.

-290

116

122

-334

252

-1

251

-207

-386

295

197

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

11

13

10

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

453

'

'

'

676

'

'

'

453

676

'

Capital expenditures

1,576

[1]

'

'

'

3,693

[2]

'

'

'

1,576

[1]

3,693

[2]

'

Goodwill

1,985

'

'

'

1,956

'

'

'

1,985

1,956

'

Total assets

33,902

'

'

'

34,983

'

'

'

33,902

34,983

'

Retail

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

6,241

[3]

5,772

[4]

5,642

[5],[6]

Operating expenses

'

'

'

'

'

'

'

'

5,535

5,065

5,113

[6]

Depreciation and amortization

'

'

'

'

'

'

'

'

142

162

159

[6]

Impairment charges

'

'

'

'

'

'

'

'

0

0

0

[6]

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

564

545

370

[6]

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

0

0

0

[6]

Impairment losses on investments

'

'

'

'

'

'

'

'

0

0

0

[2]

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

'

Other income, net

'

'

'

'

'

'

'

'

0

0

0

[6]

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

0

[6]

Interest expense

'

'

'

'

'

'

'

'

-2

-4

-4

[6]

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

562

541

366

[6]

Income tax benefit

'

'

'

'

'

'

'

'

0

0

-3

[6]

Net (Loss)/Income

'

'

'

'

'

'

'

'

562

541

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

562

541

369

[6]

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

9

5

5

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

0

'

'

'

0

'

'

'

0

0

'

Capital expenditures

30

[1]

'

'

'

19

[2]

'

'

'

30

[1]

19

[2]

'

Goodwill

260

'

'

'

231

'

'

'

260

231

'

Total assets

4,717

'

'

'

3,122

'

'

'

4,717

3,122

'

Conventional Power Generation | Texas

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

2,106

[3]

2,074

[4]

2,832

[5]

Operating expenses

'

'

'

'

'

'

'

'

1,826

1,712

1,910

Depreciation and amortization

'

'

'

'

'

'

'

'

457

458

463

Impairment charges

'

'

'

'

'

'

'

'

0

0

160

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

-177

-96

299

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

0

0

0

Impairment losses on investments

'

'

'

'

'

'

'

'

0

0

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

'

Other income, net

'

'

'

'

'

'

'

'

1

2

1

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

0

Interest expense

'

'

'

'

'

'

'

'

-1

0

-16

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-177

-94

316

Income tax benefit

'

'

'

'

'

'

'

'

0

0

0

Net (Loss)/Income

'

'

'

'

'

'

'

'

-177

-94

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

-177

-94

316

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

2,058

1,657

1,586

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

0

'

'

'

0

'

'

'

0

0

'

Capital expenditures

119

[1]

'

'

'

117

[2]

'

'

'

119

[1]

117

[2]

'

Goodwill

1,713

'

'

'

1,713

'

'

'

1,713

1,713

'

Total assets

11,656

'

'

'

10,988

'

'

'

11,656

10,988

'

Conventional Power Generation | East

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

3,209

[3]

854

[4],[7]

924

[5]

Operating expenses

'

'

'

'

'

'

'

'

2,512

754

[4]

859

Depreciation and amortization

'

'

'

'

'

'

'

'

320

137

[4]

118

Impairment charges

'

'

'

'

'

'

'

'

459

0

[4]

0

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

-82

-37

[4]

-53

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

0

0

[4]

0

Impairment losses on investments

'

'

'

'

'

'

'

'

0

0

[4]

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

[4]

'

Other income, net

'

'

'

'

'

'

'

'

28

2

[4]

2

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

[4]

0

Interest expense

'

'

'

'

'

'

'

'

-85

-20

[4]

-47

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-139

-55

[4]

-98

Income tax benefit

'

'

'

'

'

'

'

'

0

0

[4]

0

Net (Loss)/Income

'

'

'

'

'

'

'

'

-139

-55

[4]

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

[4]

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

-139

-55

[4]

-98

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

87

73

43

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

5

'

'

'

7

[4]

'

'

'

5

7

[4]

'

Capital expenditures

181

[1]

'

'

'

71

[2]

'

'

'

181

[1]

71

[2]

'

Goodwill

0

'

'

'

0

[4]

'

'

'

0

0

[4]

'

Total assets

8,437

'

'

'

6,972

[4]

'

'

'

8,437

6,972

[4]

'

Conventional Power Generation | South Central

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

874

[3]

807

[4],[7]

817

[5]

Operating expenses

'

'

'

'

'

'

'

'

750

695

[4]

703

Depreciation and amortization

'

'

'

'

'

'

'

'

98

93

[4]

89

Impairment charges

'

'

'

'

'

'

'

'

0

0

[4]

0

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

26

19

[4]

25

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

4

0

[4]

0

Impairment losses on investments

'

'

'

'

'

'

'

'

0

0

[4]

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

[4]

'

Other income, net

'

'

'

'

'

'

'

'

1

1

[4]

2

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

[4]

0

Interest expense

'

'

'

'

'

'

'

'

-18

-18

[4]

-41

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

13

2

[4]

-14

Income tax benefit

'

'

'

'

'

'

'

'

0

0

[4]

0

Net (Loss)/Income

'

'

'

'

'

'

'

'

13

2

[4]

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

[4]

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

13

2

[4]

-14

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

16

0

0

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

17

'

'

'

19

[4]

'

'

'

17

19

[4]

'

Capital expenditures

88

[1]

'

'

'

36

[2]

'

'

'

88

[1]

36

[2]

'

Goodwill

0

'

'

'

0

[4]

'

'

'

0

0

[4]

'

Total assets

2,431

'

'

'

1,935

[4]

'

'

'

2,431

1,935

[4]

'

Conventional Power Generation | West

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

475

[3]

259

[4],[7]

149

[5]

Operating expenses

'

'

'

'

'

'

'

'

318

194

[4]

92

Depreciation and amortization

'

'

'

'

'

'

'

'

55

12

[4]

10

Impairment charges

'

'

'

'

'

'

'

'

0

0

[4]

0

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

102

53

[4]

47

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

-11

7

[4]

9

Impairment losses on investments

'

'

'

'

'

'

'

'

0

0

[4]

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

[4]

'

Other income, net

'

'

'

'

'

'

'

'

1

1

[4]

0

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

[4]

0

Interest expense

'

'

'

'

'

'

'

'

-14

-2

[4]

-2

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

78

59

[4]

54

Income tax benefit

'

'

'

'

'

'

'

'

0

0

[4]

0

Net (Loss)/Income

'

'

'

'

'

'

'

'

78

59

[4]

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

[4]

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

78

59

[4]

54

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

4

0

0

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

-35

'

'

'

27

[4]

'

'

'

-35

27

[4]

'

Capital expenditures

136

[1]

'

'

'

244

[2]

'

'

'

136

[1]

244

[2]

'

Goodwill

0

'

'

'

0

[4]

'

'

'

0

0

[4]

'

Total assets

1,638

'

'

'

1,313

[4]

'

'

'

1,638

1,313

[4]

'

Conventional Power Generation | Other

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

153

[3]

173

[4]

183

[5]

Operating expenses

'

'

'

'

'

'

'

'

144

161

178

Depreciation and amortization

'

'

'

'

'

'

'

'

4

2

0

Impairment charges

'

'

'

'

'

'

'

'

0

0

0

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

5

10

5

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

6

13

9

Impairment losses on investments

'

'

'

'

'

'

'

'

-99

0

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

'

Other income, net

'

'

'

'

'

'

'

'

3

4

5

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

0

Interest expense

'

'

'

'

'

'

'

'

0

-3

-6

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-85

24

13

Income tax benefit

'

'

'

'

'

'

'

'

-29

3

0

Net (Loss)/Income

'

'

'

'

'

'

'

'

-56

21

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

-56

21

13

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

64

69

25

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

188

'

'

'

322

'

'

'

188

322

'

Capital expenditures

15

[1]

'

'

'

16

[2]

'

'

'

15

[1]

16

[2]

'

Goodwill

0

'

'

'

0

'

'

'

0

0

'

Total assets

468

'

'

'

442

'

'

'

468

442

'

Alternative Energy

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

233

[3]

125

[4]

22

[5]

Operating expenses

'

'

'

'

'

'

'

'

147

87

62

Depreciation and amortization

'

'

'

'

'

'

'

'

108

49

23

Impairment charges

'

'

'

'

'

'

'

'

0

0

0

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

-22

-11

-63

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

-4

0

4

Impairment losses on investments

'

'

'

'

'

'

'

'

0

0

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

'

Other income, net

'

'

'

'

'

'

'

'

2

0

3

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

0

Interest expense

'

'

'

'

'

'

'

'

-57

-26

-7

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-81

-37

-63

Income tax benefit

'

'

'

'

'

'

'

'

0

0

0

Net (Loss)/Income

'

'

'

'

'

'

'

'

-81

-37

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

27

20

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

-108

-57

-63

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

23

20

23

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

150

'

'

'

163

'

'

'

150

163

'

Capital expenditures

818

[1]

'

'

'

2,700

[2]

'

'

'

818

[1]

2,700

[2]

'

Goodwill

12

'

'

'

12

'

'

'

12

12

'

Total assets

6,213

'

'

'

5,367

'

'

'

6,213

5,367

'

NRG Yield

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

313

[3]

175

[4]

164

[5]

Operating expenses

'

'

'

'

'

'

'

'

134

119

114

Depreciation and amortization

'

'

'

'

'

'

'

'

51

25

22

Impairment charges

'

'

'

'

'

'

'

'

0

0

'

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

128

31

28

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

22

19

13

Impairment losses on investments

'

'

'

'

'

'

'

'

0

0

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

'

Other income, net

'

'

'

'

'

'

'

'

2

1

2

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

0

Interest expense

'

'

'

'

'

'

'

'

-35

-28

-19

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

117

23

24

Income tax benefit

'

'

'

'

'

'

'

'

8

10

9

Net (Loss)/Income

'

'

'

'

'

'

'

'

109

13

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

13

'

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

96

[1]

13

15

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

0

0

0

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

227

'

'

'

220

'

'

'

227

220

'

Capital expenditures

116

[1]

'

'

'

478

[2]

'

'

'

116

[1]

478

[2]

'

Goodwill

0

'

'

'

0

'

'

'

0

0

'

Total assets

2,313

'

'

'

1,964

'

'

'

2,313

1,964

'

Corporate

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

7

[3]

17

[4],[7]

11

[5]

Operating expenses

'

'

'

'

'

'

'

'

50

47

[4]

30

Depreciation and amortization

'

'

'

'

'

'

'

'

21

12

[4]

12

Impairment charges

'

'

'

'

'

'

'

'

'

107

[4]

0

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

128

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

-192

-149

[4]

-31

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

0

-2

[4]

0

Impairment losses on investments

'

'

'

'

'

'

'

'

0

-2

[4]

-495

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

296

[4]

'

Other income, net

'

'

'

'

'

'

'

'

74

26

[4]

21

Loss on debt extinguishment

'

'

'

'

'

'

'

'

-50

-51

[4]

-175

Interest expense

'

'

'

'

'

'

'

'

-735

-578

[4]

-571

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-903

-460

[4]

-1,251

Income tax benefit

'

'

'

'

'

'

'

'

-261

-340

[4]

-847

Net (Loss)/Income

'

'

'

'

'

'

'

'

-642

-120

[4]

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

[4]

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

-642

-120

[4]

-404

Operating revenues include inter-segment sales and net derivative gains and losses of:

'

'

'

'

'

'

'

'

7

10

0

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

0

'

'

'

10

[4]

'

'

'

0

10

[4]

'

Capital expenditures

73

[1]

'

'

'

12

[2]

'

'

'

73

[1]

12

[2]

'

Goodwill

0

'

'

'

0

[4]

'

'

'

0

0

[4]

'

Total assets

25,290

'

'

'

28,330

[4]

'

'

'

25,290

28,330

[4]

'

Eliminations

'

'

'

'

'

'

'

'

'

'

'

Income Statement

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

-2,316

-1,834

-1,665

Operating expenses

'

'

'

'

'

'

'

'

-2,307

-1,819

-1,673

Depreciation and amortization

'

'

'

'

'

'

'

'

0

0

0

Impairment charges

'

'

'

'

'

'

'

'

0

0

0

Acquisition-related transaction and integration costs

'

'

'

'

'

'

'

'

0

'

'

Operating income/(loss)

'

'

'

'

'

'

'

'

-9

-15

8

Equity in earnings/(loss) of unconsolidated affiliates

'

'

'

'

'

'

'

'

-10

0

0

Impairment losses on investments

'

'

'

'

'

'

'

'

0

0

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

'

Other income, net

'

'

'

'

'

'

'

'

-99

-18

-17

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

0

0

Interest expense

'

'

'

'

'

'

'

'

99

18

16

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-19

-15

7

Income tax benefit

'

'

'

'

'

'

'

'

0

0

-2

Net (Loss)/Income

'

'

'

'

'

'

'

'

-19

-15

'

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

-6

0

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

-13

-15

9

Balance sheet

'

'

'

'

'

'

'

'

'

'

'

Equity investments in affiliates

-99

'

'

'

-92

'

'

'

-99

-92

'

Capital expenditures

'

[1]

'

'

'

0

[2]

'

'

'

'

[1]

0

[2]

'

Goodwill

0

'

'

'

0

'

'

'

0

0

'

Total assets

($29,261)

'

'

'

($25,450)

'

'

'

($29,261)

($25,450)

'

Customers

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information

'

'

'

'

'

'

'

'

'

'

'

Threshold percentage of the Company's consolidated revenues attributable to a customer

'

'

'

'

'

'

'

'

10.00%

'

'

[1]

Includes accruals

[2]

Includes accruals.

[3]

(b) Operating revenues include inter-segment sales and net derivative gains and losses of:$9 $2,058 $87 $16 $4 $64 $23 $— $7

[4]

(c) Operating revenues include inter-segment sales and net derivative gains and losses of:$5 $1,657 $73 $— $— $69 $20 $— $10

[5]

(f) Operating revenues include inter-segment sales and net derivative gains and losses of:$5 $1,586 $43 $— $— $25 $23 $— $—

[6]

Includes Green Mountain Energy results and Energy Plus results for the period October 1, 2011 to December 31, 2011.

[7]

Includes GenOn results for the period December 15, 2012 to December 31, 2012.

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Numerator:	'	'	'	'	'	'	'	'	'	'	'
Net income/(loss) attributable to NRG Energy, Inc.	($290)	$116	$122	($334)	$252	($1)	$251	($207)	($386)	$295	$197
Dividends for preferred shares	'	'	'	'	'	'	'	'	-9	-9	-9
(Loss)/Income Available to Common Stockholders	'	'	'	'	'	'	'	'	($395)	$286	$188
Denominator (Basic EPS):	'	'	'	'	'	'	'	'	'	'	'
Weighted average number of common shares outstanding	323	323	323	323	247	228	228	228	323	232	240
Basic earnings per share:	'	'	'	'	'	'	'	'	'	'	'
(Loss)/Earnings per weighted average common share — basic	($0.90)	$0.36	$0.38	($1.03)	$1.02	($0.01)	$1.09	($0.92)	($1.22)	$1.23	$0.78
Denominator (Diluted EPS):	'	'	'	'	'	'	'	'	'	'	'
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	'	'	'	'	'	'	'	'	0	2	1
Total dilutive shares	323	327	327	323	249	228	229	228	323	234	241
Diluted earnings per share:	'	'	'	'	'	'	'	'	'	'	'
(Loss)/Earnings per weighted average common share — diluted	($0.90)	$0.35	$0.37	($1.03)	$1.01	($0.01)	$1.08	($0.92)	($1.22)	$1.22	$0.78
Antidilutive securities excluded from computation of earnings per share	'	'	'	'	'	'	'	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	'	'	'	'	'	'	'	25	24	23
Equity compensation	'	'	'	'	'	'	'	'	'	'	'
Antidilutive securities excluded from computation of earnings per share	'	'	'	'	'	'	'	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	'	'	'	'	'	'	'	9	8	7
Embedded derivative of 3.625% redeemable perpetual preferred stock	'	'	'	'	'	'	'	'	'	'	'
Antidilutive securities excluded from computation of earnings per share	'	'	'	'	'	'	'	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	'	'	'	'	'	'	'	16	16	16
Embedded derivative of 3.625% redeemable perpetual preferred stock	'	'	'	'	'	'	'	'	'	'	'
Antidilutive securities excluded from computation of earnings per share	'	'	'	'	'	'	'	'	'	'	'
Dividend rate of Preferred Stock (as a percent)	'	'	'	'	'	'	'	'	3.63%	3.63%	'

Income_Taxes_Provision_Details

Income Taxes (Provision) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Income tax refunds received	$87	$8	'
Deferred Tax Assets, Valuation Allowance	291	191	'
Current	'	'	'
U.S. Federal	0	0	-538
State	11	20	10
Foreign	0	13	16
Total — current	11	33	-512
Deferred	'	'	'
U.S. Federal	-207	-326	-317
State	-57	-24	-5
Foreign	-29	-10	-9
Total — deferred	-293	-360	-331
Income tax benefit	-282	-327	-843
Effective income tax rate (as a percent)	44.50%	2725.00%	130.50%
Domestic and foreign components of income from continuing operations before income tax expense	'	'	'
U.S.	-549	-41	-680
Foreign	-85	29	34
Income/(loss) before income taxes	-634	-12	-646
U.S. federal statutory rate (as a percent)	35.00%	35.00%	35.00%
Reconciliation of the U.S. federal statutory rate to NRG's effective rate from continuing operations	'	'	'
Income/(loss) before income taxes	-634	-12	-646
Tax at 35%	-222	-4	-226
State taxes, including change in rate, net of federal benefit	11	1	15
Foreign operations	5	-24	-3
Federal and state tax credits	36	158	1
Valuation allowance	-5	5	-63
Expiration/utilization of capital losses	10	0	45
Reversal of valuation allowance on expired/utilized capital losses	-10	0	-45
Impact of non-taxable equity earnings	-14	-7	0
Bargain purchase gain related to GenOn acquisition	0	-104	0
Foreign earnings	0	0	4
Interest accrued on uncertain tax positions	-3	2	2
Production tax credit	14	14	14
Reversal of uncertain tax position reserves	-11	-13	-561
Other	-1	-11	4
Income tax benefit	($282)	($327)	($843)
Effective income tax rate (as a percent)	44.50%	2725.00%	130.50%

Income_Taxes_Deferred_Details_

Income Taxes (Deferred) (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Deferred tax liabilities:	'	'
Emissions allowances	$15,000,000	$15,000,000
Difference between book and tax basis of property	22,000,000	123,000,000
Derivatives, net	334,000,000	323,000,000
Goodwill	191,000,000	165,000,000
Cumulative translation adjustments	9,000,000	19,000,000
Intangibles amortization (excluding goodwill)	0	85,000,000
Investment in projects	-540,000,000	-52,000,000
Other	0	0
Total deferred tax liabilities	1,111,000,000	782,000,000
Deferred tax assets:	'	'
Deferred compensation, pension, accrued vacation and other reserves	203,000,000	232,000,000
Discount/premium on notes	111,000,000	156,000,000
Differences between book and tax basis of contracts	285,000,000	343,000,000
Pension and other postretirement benefits	168,000,000	274,000,000
Equity compensation	57,000,000	57,000,000
Bad debt reserve	18,000,000	14,000,000
U.S. capital loss carryforwards	1,000,000	1,000,000
U.S. Federal net operating loss carryforwards	1,381,000,000	605,000,000
Foreign net operating loss carryforwards	77,000,000	89,000,000
State net operating loss carryforwards	161,000,000	89,000,000
Foreign capital loss carryforwards	1,000,000	1,000,000
Deferred financing costs	3,000,000	33,000,000
Federal and state tax credits	308,000,000	258,000,000
Federal benefit on state uncertain tax positions	23,000,000	18,000,000
Other	23,000,000	7,000,000
Total deferred tax assets	2,840,000,000	2,177,000,000
Valuation allowance	-291,000,000	-191,000,000
Total deferred tax assets, net of valuation allowance	2,549,000,000	1,986,000,000
Net deferred tax asset	1,438,000,000	1,204,000,000
NRG's net deferred tax position	'	'
Net deferred tax asset — current	258,000,000	56,000,000
Net deferred tax asset — noncurrent	1,202,000,000	1,203,000,000
Deferred Tax Liabilities, Net, Noncurrent	-22,000,000	-55,000,000
Net deferred tax assets (prior to any valuation allowance)	1,400,000,000	1,200,000,000
Future Taxable Income to Fully Realize Net Federal and State Unitary Deferred Tax Assets Before Expiration	3,100,000,000	'
Domestic Tax Authority	'	'
NRG's net deferred tax position	'	'
Operating Loss Carryforwards	1,400,000,000	'
State and Local Jurisdiction	'	'
Deferred tax assets:	'	'
Valuation allowance	-216,000,000	'
NRG's net deferred tax position	'	'
Operating Loss Carryforwards	161,000,000	'
Foreign Tax Authority	'	'
Deferred tax assets:	'	'
Valuation allowance	-75,000,000	'
NRG's net deferred tax position	'	'
Operating Loss Carryforwards	77,000,000	'
Expiration Date 2014 to 2021 | Foreign Tax Authority	'	'
NRG's net deferred tax position	'	'
Operating Loss Carryforwards	4,000,000	'
No Expiration Date | Foreign Tax Authority	'	'
NRG's net deferred tax position	'	'
Operating Loss Carryforwards	$73,000,000	'

Income_Taxes_Tax_PayableReceiv

Income Taxes (Tax Payable/Receivable) (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Taxes receivable and payable	'	'
Current taxes payable	$12	'
Current taxes receivable	551	'
Federal refund receivable on prior year returns	539	633
Noncurrent taxes receivable	65	'
Domestic Tax Authority	'	'
Taxes receivable and payable	'	'
Current taxes payable	11	'
State and Local Jurisdiction	'	'
Taxes receivable and payable	'	'
Current taxes payable	$1	'

Income_Taxes_Uncertain_Benefit

Income Taxes (Uncertain Benefits) (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Uncertain tax benefits	'	'	'
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$115	'	'
Liability for Uncertain Tax Positions, Noncurrent	61	72	'
Interest accrued on uncertain tax positions	-3	2	2
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	'	5	'
Accrued interest and penalties related to unrecognized tax benefits	14	15	'
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	539	633	'
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	'	536	'
Uncertain tax benefits reconciliation	'	'	'
Balance as of January 1	193	'	178
Increase due to current year positions	2	21	'
Decrease due to current year positions	0	-3	'
Increase due to prior year positions	4	13	'
Decrease due to prior year positions	-40	-21	'
Increase due to acquisitions	0	5	'
Decrease due to settlements and payments	-44	0	'
Uncertain tax benefits as of December 31	115	193	'
IRS Settlement	'	'	'
Uncertain tax benefits	'	'	'
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	'	633	'
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	'	$536	'

StockBased_Compensation_NQSO_D

Stock-Based Compensation (NQSO) (Details) (USD $)

0 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Performance Stock Units

Performance Stock Units

Performance Stock Units

Non Qualified Stock Options Portion One

Non Qualified Stock Options Portion Two

Non-Qualified Stock Options

Non-Qualified Stock Options

Non-Qualified Stock Options

Restricted Stock Units (RSUs)

Restricted Stock Units (RSUs)

Restricted Stock Units (RSUs)

Long-Term Incentive Plan, or LTIP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock authorized for issuance under the LTIP (in shares)

'

22,000,000

22,000,000

'

'

'

'

'

'

'

'

'

'

'

Common stock remaining available for grants under NRG's LTIP (in shares)

'

7,238,065

7,580,318

'

'

'

'

'

'

'

'

'

'

'

Shares Authorized for Issuance Under GenOn LTIP

'

5,558,390

'

'

'

'

'

'

'

'

'

'

'

'

GenOn LTIP, Shares Remaining

'

1,053,485

'

'

'

'

'

'

'

'

'

'

'

'

Consideration Paid, Equity Interests Issued and Issuable

$28

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock-Based Compensation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)

'

'

'

'

$20.80

'

'

'

'

'

'

$23.37

$17.90

$22.78

Vesting period from the date of issuance (in years)

'

'

'

'3 years

'

'

'3 years

'

'

'

'

'4 years

'

'

NQSO activity and changes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award

'

'

'

'PUs are paid out upon vesting if the Measurement Price is equal to or greater than Threshold Price. The Threshold Price, Target Price and Maximum Price are determined on the date of issuance. The payout for each PU will be equal to: (i) a pro-rata amount between 0.5 and 1 share of common stock, if the Measurement Price is equal to or greater than the target Threshold Price but less than the Target Price; (ii) one share of common stock, if the Measurement Price equals the Target Price; (iii) a pro-rata amount between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price; and (iv) two shares of common stock, if the Measurement Price is equal to, or greater than, the Maximum Price.

'

'

'10

'6

'

'

'

'

'

'

Outstanding at the beginning of the period (in shares)

'

'

'

'

'

'

'

'

6,677,885

'

'

'

'

'

Forfeited (in shares)

'

'

'

'

'

'

'

'

-1,044,902

'

'

'

'

'

Exercised (in shares)

'

'

'

'

'

'

'

'

-1,656,002

'

'

'

'

'

Outstanding at the end of the period (in shares)

'

'

'

'

'

'

2,800,000

1,200,000

3,976,981

6,677,885

'

'

'

'

Exercisable at the end of the period (in shares)

'

'

'

'

'

'

'

'

3,592,810

'

'

'

'

'

Weighted Average Exercise Price at the beginning of the period (in dollars per share)

'

'

'

'

'

'

'

'

$28.85

'

'

'

'

'

Forfeited - Weighted Average Exercise Price (in dollars per share)

'

'

'

'

'

'

'

'

$27.75

'

'

'

'

'

Exercised - Weighted Average Exercise Price (in dollars per share)

'

'

'

'

'

'

'

'

$14.28

'

'

'

'

'

Weighted Average Exercise Price at the end of the period (in dollars per share)

'

'

'

'

'

'

'

'

$35.20

$28.85

'

'

'

'

Exercisable - Weighted Average Exercise Price (in dollars per share)

'

'

'

'

'

'

'

'

$31.80

'

'

'

'

'

Options Outstanding - Weighted Average Remaining Contractual Term (in years)

'

'

'

'

'

'

'

'

'4 years

'4 years

'

'

'

'

Options Exercisable - Weighted Average Remaining Contractual Term (in years)

'

'2 years

'4 years

'

'

'

'

'

'3 years

'

'

'

'

'

Options Outstanding - Aggregate Intrinsic Value

'

'

'

'

'

'

'

'

17

17

'

'

'

'

Options Exercisable - Aggregate Intrinsic Value

'

'

'

'

'

'

'

'

13

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value

'

'

'

'

'

'

'

'

$0

$0

$8.73

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value

'

'

'

'

'

'

'

'

19

0.3

0.2

'

'

'

Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options

'

'

'

'

'

'

'

'

$33

$1

$2

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum

'

'

'

'

46.96%

44.77%

'

'

'

42.38%

41.28%

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum

'

'

'

'

53.15%

53.81%

'

'

'

42.57%

42.57%

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum

'

'

'

'

0.50%

0.59%

'

'

'

1.42%

1.54%

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Maximum

'

'

'

'

1.41%

1.66%

'

'

'

2.71%

3.01%

'

'

'

StockBased_Compensation_RSU_De

Stock-Based Compensation (RSU) (Details 2) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance Stock Units	'	'	'
Stock-Based Compensation	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	314,300	647,200	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$20.80	$21.88	'
Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	'	$20.80	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	296,200	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$23.28	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-36,700	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$19.89	'	'
Restricted Stock Units (RSUs)	'	'	'
Stock-Based Compensation	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	2,023,179	2,608,551	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$21.22	$21.28	'
Granted (in units)	617,009	'	'
Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$23.37	$17.90	$22.78
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	322,448	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$21.34	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-879,933	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$22.64	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$22	$18	$2

StockBased_Compensation_DSU_MS

Stock-Based Compensation (DSU MSU PSU) (Details 3) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Information	'	'	'	'
Number of types of awards	5	'	'	'
Minimum tax withholding paid for share-based compensation	$13	$6	$1	'
Allocated Share-based Compensation Expense	40	40	27	'
Tax benefit recognized	-12	-8	-1	'
Non-vested Compensation Cost, Unrecognized Total Cost	47	'	'	'
Non-Qualified Stock Options	'	'	'	'
Supplemental Information	'	'	'	'
Allocated Share-based Compensation Expense	4	6	8	'
Non-vested Compensation Cost, Unrecognized Total Cost	1	'	'	'
Non-vested Compensation Cost, Weighted Average Recognition Period Remaining (in years)	'1 year 1 month	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum	'	42.38%	41.28%	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum	'	42.57%	42.57%	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'	'6 years	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum	'	1.42%	1.54%	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Maximum	'	2.71%	3.01%	'
Restricted Stock Units (RSUs)	'	'	'	'
Stock-Based Compensation	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	2,023,179	2,608,551	'	'
Company's outstanding DSU awards, and changes during the year	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$21.22	$21.28	'	'
Granted (in units)	617,009	'	'	'
Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$23.37	$17.90	$22.78	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-879,933	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$22.64	'	'	'
Supplemental Information	'	'	'	'
Allocated Share-based Compensation Expense	18	21	12	'
Non-vested Compensation Cost, Unrecognized Total Cost	18	'	'	'
Non-vested Compensation Cost, Weighted Average Recognition Period Remaining (in years)	'1 year 5 months	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	-322,448	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$21.34	'	'	'
Deferred Stock Units	'	'	'	'
Company's outstanding DSU awards, and changes during the year	'	'	'	'
Balance outstanding at the beginning of the period (in units)	697,515	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	'	$20.91	'	'
Granted (in units)	205,667	'	'	'
Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$23.18	$16.33	$24.31	'
Balance outstanding at the end of the period (in units)	378,546	697,515	'	'
Balance outstanding at the end of the period, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$19.78	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-524,636	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$22.55	'	'	'
Aggregate intrinsic value for DSUs outstanding	7	15	'	8
Aggregate intrinsic values for DSUs converted to common stock during the period	12	1.4	0.4	'
Supplemental Information	'	'	'	'
Allocated Share-based Compensation Expense	2	2	2	'
Non-vested Compensation Cost, Unrecognized Total Cost	0	'	'	'
Non-vested Compensation Cost, Weighted Average Recognition Period Remaining (in years)	'0 years	'	'	'
Market Stock Unit	'	'	'	'
Stock-Based Compensation	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	'MSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's Total Shareholder Return, or TSR. Each MSU represents the potential to receive NRG common stock after the completion of three years of service from the date of grant. The number of shares of NRG common stock to be paid (if any) as of the vesting date for each MSU will depend on the TSR. The number of shares of common stock to be paid as of the vesting date for each MSU is equal to: (i) one half of one share of common stock if the TSR has decreased by no more than 50% of the value of the common stock on the date of grant; (ii) one share of common stock, if the TSR equals the value of the common stock on the date of grant; and (iii) two shares of common stock if the TSR is 200% or greater of the value of the common stock on the date of grant. If the TSR is less than 50% of the value of the common stock on the date of grant, no common stock will be paid. If the TSR is between 50% and 200%, shares awarded are interpolated. The value of the common stock on the date of grant is based on the 20-day average of the common stock closing price.	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	1,836,506,000,000	1,003,920,000,000	'	'
Company's outstanding DSU awards, and changes during the year	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$24.72	$22.43	'	'
Granted (in units)	1,066,626,000,000	'	'	'
Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$27.46	$22.11	$27.59	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-20,000,000,000	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$26.64	'	'	'
Supplemental Information	'	'	'	'
Allocated Share-based Compensation Expense	14	7	0	'
Non-vested Compensation Cost, Unrecognized Total Cost	28	'	'	'
Non-vested Compensation Cost, Weighted Average Recognition Period Remaining (in years)	'1 year 8 months	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum	29.60%	25.42%	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum	35.98%	52.30%	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'	'3 years	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum	0.29%	0.13%	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Maximum	0.55%	0.33%	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	-214,040,000,000	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$24.16	'	'	'
Performance Stock Units	'	'	'	'
Stock-Based Compensation	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	'PUs are paid out upon vesting if the Measurement Price is equal to or greater than Threshold Price. The Threshold Price, Target Price and Maximum Price are determined on the date of issuance. The payout for each PU will be equal to: (i) a pro-rata amount between 0.5 and 1 share of common stock, if the Measurement Price is equal to or greater than the target Threshold Price but less than the Target Price; (ii) one share of common stock, if the Measurement Price equals the Target Price; (iii) a pro-rata amount between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price; and (iv) two shares of common stock, if the Measurement Price is equal to, or greater than, the Maximum Price.	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	314,300	647,200	'	'
Company's outstanding DSU awards, and changes during the year	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$20.80	$21.88	'	'
Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	'	$20.80	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-36,700	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$19.89	'	'	'
Supplemental Information	'	'	'	'
Allocated Share-based Compensation Expense	2	4	5	'
Non-vested Compensation Cost, Unrecognized Total Cost	$0	'	'	'
Non-vested Compensation Cost, Weighted Average Recognition Period Remaining (in years)	'0 years	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum	'	46.96%	44.77%	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum	'	53.15%	53.81%	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'	'3 years	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum	'	0.50%	0.59%	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Maximum	'	1.41%	1.66%	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	-296,200	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$23.28	'	'	'
Minimum | Non-Qualified Stock Options	'	'	'	'
Supplemental Information	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'	'	'6 years	'
Minimum | Market Stock Unit	'	'	'	'
Supplemental Information	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'3 years	'	'	'
Minimum | Performance Stock Units	'	'	'	'
Supplemental Information	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'	'	'3 years	'
Maximum | Non-Qualified Stock Options	'	'	'	'
Supplemental Information	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'	'	'6 years 6 months	'
Maximum | Market Stock Unit	'	'	'	'
Supplemental Information	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'4 years	'	'	'
Maximum | Performance Stock Units	'	'	'	'
Supplemental Information	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'	'	'5 years	'

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jul. 17, 2012

Gladstone

Gladstone

Gladstone

GenConn

GenConn

GenConn

Kraftwerke Schkopau GBR

Kraftwerke Schkopau GBR

Kraftwerke Schkopau GBR

Saale Energie GmbH

Related Party Transactions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenues from Related Parties Included in Operating Revenues

'

$11

$13

$10

$6

$7

$7

$5

$6

$3

[1]

'

'

'

'

Interest Income, Related Party

'

0

2

5

'

'

'

0

[2]

0

1

[1]

0

2

[3]

4

'

Investment Owned, Percent of Net Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

Management Fees Revenue

$1

$10

'

'

'

'

'

'

'

'

'

'

'

'

[1]

The period in 2011 is from January 1, 2011 to June 30, 2011.

[2]

The period in 2012 is from January 1, 2012 to July 17, 2012.

[3]

Discounts of $4 million and $5 million are related to current maturities in 2013 and 2012, respectively.

Commitments_and_Contingencies_2

Commitments and Contingencies (Operating Leases) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Lease Commitments	'	'	'
Lease expense	$88,000,000	$67,000,000	$81,000,000
Coal, Gas and Transportation Commitments	'	'	'
Coal, Gas and Transportation Commitments	'	'	'
Purchases	2,800,000,000	1,400,000,000	1,600,000,000
Dickerson Morgantown [Member]	'	'	'
Coal, Gas and Transportation Commitments	'	'	'
Leased Interest	100.00%	'	'
GenOn Mid-Atlantic	'	'	'
Future commitments under coal, gas and transportation contractual agreements	'	'	'
2013	131,000,000	'	'
2014	110,000,000	'	'
2015	150,000,000	'	'
2016	144,000,000	'	'
2017	105,000,000	'	'
Thereafter	686,000,000	'	'
Total	1,326,000,000	'	'
REMA	'	'	'
Future commitments under coal, gas and transportation contractual agreements	'	'	'
2013	63,000,000	'	'
2014	56,000,000	'	'
2015	61,000,000	'	'
2016	63,000,000	'	'
2017	55,000,000	'	'
Thereafter	400,000,000	'	'
Total	698,000,000	'	'
Other Property	'	'	'
Future commitments under coal, gas and transportation contractual agreements	'	'	'
2013	79,000,000	'	'
2014	78,000,000	'	'
2015	63,000,000	'	'
2016	41,000,000	'	'
2017	38,000,000	'	'
Thereafter	138,000,000	'	'
Total	$437,000,000	'	'
Shawville	'	'	'
Coal, Gas and Transportation Commitments	'	'	'
Leased Interest	100.00%	'	'
Keystone, Shelocta, PA	'	'	'
Coal, Gas and Transportation Commitments	'	'	'
Leased Interest	16.45%	'	'
Conemaugh, New Florence, PA	'	'	'
Coal, Gas and Transportation Commitments	'	'	'
Leased Interest	16.67%	'	'

Commitments_and_Contingencies_3

Commitments and Contingencies (Commitments) (Details 2) (USD $)	12 Months Ended					12 Months Ended				1 Months Ended	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2013	Dec. 31, 2013
	year			Lignite Contract with Texas Westmoreland Coal Co.	Lignite Contract with Texas Westmoreland Coal Co.	Lignite Contract with Texas Westmoreland Coal Co.	Coal, Gas and Transportation Commitments	Coal, Gas and Transportation Commitments	Coal, Gas and Transportation Commitments	Natural Gas Litigation [Member]	Natural Gas Litigation [Member]
				Letters of Credit Posted by NRG	Corporate Guarantee of Bond Obligation	Texas Westmoreland Coal Co.				GenOn Energy	GenOn Energy
										legal_cases	Lawsuits
Commitments and Contingencies	'		'	'	'	'	'	'	'	'	'
Nuclear Insurance Financial Protection Pool, Maximum Assessment, Adminstrative Fee, As a Percent	5.00%		'	'	'	'	'	'	'	'	'
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals	$20,000,000		'	'	'	'	'	'	'	'	'
Loss Contingency, Claims Settled and Dismissed, Number	'		'	'	'	'	'	'	'	1	4
Purchases	'		'	'	'	'	2,800,000,000	1,400,000,000	1,600,000,000	'	'
Minimum purchase commitment	'		'	'	'	'	'	'	'	'	'
2013	24,000,000		'	'	'	'	963,000,000	'	'	'	'
2014	18,000,000		'	'	'	'	272,000,000	'	'	'	'
2015	12,000,000		'	'	'	'	254,000,000	'	'	'	'
2016	10,000,000		'	'	'	'	220,000,000	'	'	'	'
2017	1,000,000		'	'	'	'	136,000,000	'	'	'	'
Thereafter	0		'	'	'	'	719,000,000	'	'	'	'
Total	65,000,000	[1]	'	'	'	'	2,564,000,000	'	'	'	'
Maximum remaining term under individual purchased power contract (in years)	5		'	'	'	'	'	'	'	'	'
Lignite Contract with Texas Westmoreland Coal Co.	'		'	'	'	'	'	'	'	'	'
Mining period for which option to extend can be done	'		'	'	'	'two five-year intervals	'	'	'	'	'
Bond obligation imposed by Railroad Commission of Texas	'		'	'	'	107,500,000	'	'	'	'	'
Obligation guaranteed by NRG Energy, Inc	4,081,000,000		3,804,000,000	'	76,000,000	'	'	'	'	'	'
Surety Bond in Support of Guarantee	'		'	$31,500,000	'	'	'	'	'	'	'
[1]	As of December 31, 2013, the maximum remaining term under any individual purchased power contract is five years.

Commitments_and_Contingencies_4

Commitments and Contingencies (Texas, Nuclear) (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013
	Months
	Weeks
	year
Loss Contingencies [Line Items]	'
Nuclear insurance liability limit per incident	$13,600,000,000
Required nuclear liability insurance	375,000,000
Nuclear financial protection pool mandated by the Price-Anderson Act	13,200,000,000
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident	127,000,000
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident	19,000,000
44% maximum assessment	44.00%
Nuclear Insurance Financial Protection Pool Nuclear Operator Maximum Annual Assessment	8,000,000
Maximum liability per nuclear incident	112,000,000
Mutual property insurance additional blanket policy property coverage	1,000,000,000
Nuclear property insurance coverage limit per individual insured	1,750,000,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery	4,000,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	1,980,000
Accidental outage maximum recovery for lost revenues	215,600,000
Waiting period for additional revenue loss policy	8
Multiplier that the industry mutual insurance company may assess against insureds premium	10
The number of months a nuclear industry mutual insurance company will respond to retrospective premium adjustments	24
Number of years board of directors of industry mutual insurance company can adjust policy after policy expires	6
Nuclear Event [Member]	'
Loss Contingencies [Line Items]	'
Total nuclear property insurance coverage	2,750,000,000
Non-nuclear Event [Member]	'
Loss Contingencies [Line Items]	'
Total nuclear property insurance coverage	1,500,000,000
Accidental outage maximum recovery for lost revenues	$144,000,000

Commitments_and_Contigencies_C

Commitments and Contigencies (Contingencies) (Details 4) (USD $)

3 Months Ended

9 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

4 Months Ended

9 Months Ended

1 Months Ended

13 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

Mar. 31, 2014

Sep. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2008

Jun. 30, 2013

Mar. 31, 2013

Jan. 31, 2013

Jun. 30, 2013

Apr. 30, 2012

Jul. 31, 2013

Apr. 30, 2013

Sep. 30, 2012

Jun. 30, 2013

Apr. 30, 2011

Sep. 30, 2010

Dec. 31, 2012

Dec. 31, 2013

Feb. 28, 2008

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Mar. 31, 2012

Dec. 31, 2002

Notice of Intent to File Citizens Suit [Member]

Notice of Intent to File Citizens Suit [Member]

Notice of Intent to File Citizens Suit [Member]

Ormond Beach Alleged Federal Clean Water Act Violations [Member]

Cheswick Class Action [Member]

New Source Review [Member]

New Source Review [Member]

Agreement To Acquire All Outstanding Shares of GenOn

GenOn Energy

GenOn Mid-Atlantic and GenOn MD Ash Management [Member]

GenOn Mid-Atlantic and GenOn MD Ash Management [Member]

GenOn Mid-Atlantic

Energy Plus

Global Warming

Natural Gas Litigation [Member]

Natural Gas Litigation [Member]

Mayland Fly Ash

Mayland Fly Ash

Mayland Fly Ash

Mayland Fly Ash

Mayland Fly Ash

Keystone Conemaugh

Subsequent Event

NEW JERSEY

PENNSYLVANIA

NEW YORK

California Department Of Water Resources [Member]

California Department Of Water Resources [Member]

California Department Of Water Resources [Member]

permit

mi

nov

Lawsuits

Texas Franchise Audit [Member]

Brandywine Litigation, Coal Combusion Waste [Member]

Brandywine Litigation, Coal Combusion Waste [Member]

Class Action Related to Sales, Marketing and Business Practices [Member]

Environmental Issue

GenOn Energy

GenOn Energy

fly_ash_facility

GenOn Mid-Atlantic

GenOn Mid-Atlantic

GenOn Mid-Atlantic

GenOn Mid-Atlantic

REMA

Big Cajun II Alleged Opacity Violations [Member]

Energy Plus

Energy Plus

Energy Plus

facility

environmental_advocy_group

Lawsuits

companies

legal_cases

Lawsuits

Environmental Issue

Environmental Issue

Environmental Issue

Environmental Issue

Class Action Related to Sales, Marketing and Business Practices [Member]

Class Action Related to Sales, Marketing and Business Practices [Member]

Class Action Related to Sales, Marketing and Business Practices [Member]

fly_ash_facility

Lawsuits

Lawsuits

Lawsuits

Loss Contingencies

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Damages Sought, Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$940,000,000

Off-market Lease, Unfavorable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

604,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Out of Market Value of the Lease Obligation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

186,000,000

'

'

'

'

'

'

'

Loss Contingency, Settlement Agreement, Consideration

12,000,000

'

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

47,000

'

'

'

'

'

'

Distance From Facility of People who Own Property

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Litigation Settlement, Review Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

number of companies also included in lawsuit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Civil Penalties

'

3,500,000

'

'

'

100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,900,000

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Loss in Period

'

10,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Range of Possible Loss, Maximum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum Civil Penalties which May Be Assumed

'

'

'

'

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Civil Penalties, Accrued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600,000

'

'

'

'

'

'

'

'

Loss Contingency Accrual, at Carrying Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

47,000,000

'

'

'

'

'

'

'

'

20,000,000

'

Long-term Purchase Commitment, Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

Payments for Legal Settlements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,000,000

'

'

Loss Contingency, Number of Days After Approval, Payment Due

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

Loss Contingency, Number of Fast Charge Stations to Be Installed in California

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

Loss Contingency, Number of Parking Spaces Required

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

Loss Contingency, Number of Multi-Family Complexes Able to Charge

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

Loss Contingency, Number of Plaintiffs

'

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

6

'

'

'

'

'

'

'

'

'

'

2

2

2

'

'

'

Loss Contingency, Pending Claims, Number

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Claims Settled and Dismissed, Number

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6

'

1

4

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Number of NOVs Issued

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Facilities

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency Obligation, Legal Fees

'

'

'

'

'

'

'

'

79,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency Obligation, Supplemental Environmental Projects

'

'

'

'

'

'

'

'

65,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency Obligation, Monitoring Costs

'

'

'

'

'

'

'

'

15,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Fly Ash Facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

3

'

'

'

'

'

'

'

'

'

Loss Contingency, Requested Period of Time for Open Disposal Cells to be Closed and Capped

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Environmental Advocacy Groups, Intervening Parties to Litigation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Permits that Regulate Polution Discharge Elimination

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Number of Days to Comply with Discharge Violation

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income Tax Examination, Penalties and Interest Accrued

'

'

'

'

'

'

'

'

'

'

'

'

'

72,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income Tax Examination, Interest Accrued

'

'

'

'

'

'

'

'

'

'

'

'

'

29,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decrease due to settlements and payments

'

'

$44,000,000

$0

'

'

'

'

'

'

'

'

'

$11,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)	1 Months Ended
In Millions, unless otherwise specified	31-May-10	Jul. 05, 2012	Dec. 31, 2011
	orders	owners
Regulatory Assets [Line Items]	'	'	'
Number of significant orders issued by FERC	2	'	'
SECA charges owed by BP Energy	'	'	$22
Regulatory Charges Settled by Third Party	'	24	'
Number of PJM Transmission Owners Who Filed Motion	'	3	'
Regulatory Charges Settled by Third Party, Additional	'	$1	'

Environmental_Matters_Details

Environmental Matters (Details) (USD $)	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2011	Sep. 30, 2012	Dec. 31, 2008	Dec. 31, 2013
Environmental Matters Disclosure [Abstract]	'	'	'	'
Impairment of Intangible Assets (Excluding Goodwill)	$160,000,000	'	'	'
Environmental Capital Expenditures, Estimated	'	'	'	332,000,000
Environmental Capital Expenditures, Estimated for Legacy GenOn	'	'	'	120,000,000
Loss Contingency, Loss in Period	'	10,500,000	'	'
Minimum Civil Penalties which May Be Assumed	'	'	200,000	'
Civil Penalties	'	$3,500,000	'	'

Cash_Flow_Information_Details

Cash Flow Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest paid, net of amount capitalized	$836	$579	$642
Income taxes paid	-60	17	26	[1]
Non-cash investing and financing activities:	'	'	'
Additions to fixed assets for accrued capital expenditures	405	563	292
Decrease to fixed assets for accrued grants and related tax impact	681	87	32
Decrease to notes receivable for equity conversion	0	0	63
Other Significant Noncash Transactions	'	'	'
Income Taxes Paid	28	'	'
Income tax refunds received	87	8	'
GenOn Energy	'	'	'
Other Significant Noncash Transactions	'	'	'
Issuance of shares for GenOn acquisition	'	$2,188	$0
[1]	income taxes paid are net of $8 million of income tax refunds received.

Guarantees_Details

Guarantees (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
	year
Guarantees [Abstract]	'	'
Fair value of guarantees	$5.40	'
Guarantor Obligations	'	'
Guarantees By Remaining Maturity, Under 1 Year	1,813	'
Guarantees By Remaining Maturity, 1-3 Years	163	'
Guarantees By Remaining Maturity, 3-5 Years	298	'
Guarantees By Remaining Maturity, Over 5 Years	1,807	'
Guarantees by Remaining Maturity, Total	4,081	3,804
Letters of credit and surety bonds	'	'
Guarantor Obligations	'	'
Guarantees By Remaining Maturity, Under 1 Year	1,654	'
Guarantees By Remaining Maturity, 1-3 Years	47	'
Guarantees By Remaining Maturity, 3-5 Years	0	'
Guarantees By Remaining Maturity, Over 5 Years	0	'
Guarantees by Remaining Maturity, Total	1,701	1,594
Letters of credit and surety bonds, maximum expiration period (in years)	1	'
Asset sales guarantee obligations	'	'
Guarantor Obligations	'	'
Guarantees By Remaining Maturity, Under 1 Year	0	'
Guarantees By Remaining Maturity, 1-3 Years	0	'
Guarantees By Remaining Maturity, 3-5 Years	275	'
Guarantees By Remaining Maturity, Over 5 Years	0	'
Guarantees by Remaining Maturity, Total	275	275
Commercial sales arrangements	'	'
Guarantor Obligations	'	'
Guarantees By Remaining Maturity, Under 1 Year	81	'
Guarantees By Remaining Maturity, 1-3 Years	112	'
Guarantees By Remaining Maturity, 3-5 Years	23	'
Guarantees By Remaining Maturity, Over 5 Years	1,338	'
Guarantees by Remaining Maturity, Total	1,554	1,579
Other guarantees	'	'
Guarantor Obligations	'	'
Guarantees By Remaining Maturity, Under 1 Year	78	'
Guarantees By Remaining Maturity, 1-3 Years	4	'
Guarantees By Remaining Maturity, 3-5 Years	0	'
Guarantees By Remaining Maturity, Over 5 Years	469	'
Guarantees by Remaining Maturity, Total	$551	$356

Jointly_Owned_Plants_Details

Jointly Owned Plants (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
South Texas Project	'
Jointly Owned Utility Plant Interests	'
Ownership Interest (as a percent)	44.00%
Property, Plant and Equipment	$2,679
Accumulated Depreciation	-1,293
Construction in Progress	19
Big Cajun II Unit 3, New Roads, LA	'
Jointly Owned Utility Plant Interests	'
Ownership Interest (as a percent)	58.00%
Property, Plant and Equipment	178
Accumulated Depreciation	-95
Construction in Progress	18
Cedar Bayou Unit 4, Baytown, TX	'
Jointly Owned Utility Plant Interests	'
Ownership Interest (as a percent)	50.00%
Property, Plant and Equipment	215
Accumulated Depreciation	-49
Construction in Progress	0
Keystone, Shelocta, PA	'
Jointly Owned Utility Plant Interests	'
Ownership Interest (as a percent)	3.70%
Property, Plant and Equipment	92
Accumulated Depreciation	-35
Construction in Progress	1
Conemaugh, New Florence, PA	'
Jointly Owned Utility Plant Interests	'
Ownership Interest (as a percent)	3.72%
Property, Plant and Equipment	82
Accumulated Depreciation	-38
Construction in Progress	$14

Unaudited_Quarterly_Financial_2

Unaudited Quarterly Financial Data (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	$2,795	$3,490	$2,930	$2,081	$2,063	$2,331	$2,166	$1,862	$11,295	$8,422	$9,079
Operating income/(loss)	-205	527	287	-266	37	86	397	-170	343	350	635
Net income/(loss) attributable to NRG Energy, Inc.	($290)	$116	$122	($334)	$252	($1)	$251	($207)	($386)	$295	$197
Weighted average number of common shares outstanding - basic (in shares)	323	323	323	323	247	228	228	228	323	232	240
Net Income/(Loss) per Weighted Average Common Share - Basic (in dollars per share)	($0.90)	$0.36	$0.38	($1.03)	$1.02	($0.01)	$1.09	($0.92)	($1.22)	$1.23	$0.78
Weighted average number of common shares outstanding - diluted (in shares)	323	327	327	323	249	228	229	228	323	234	241
Net Income/(Loss) Per Weighted Average Common Share - Diluted (in dollars per share)	($0.90)	$0.35	$0.37	($1.03)	$1.01	($0.01)	$1.08	($0.92)	($1.22)	$1.22	$0.78

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Debt Instrument	'	'
Long-term debt	$16,804	$15,866
Recourse Debt	'	'
Debt Instrument	'	'
Long-term debt	8,087	7,818
Senior Notes | Recourse Debt	'	'
Debt Instrument	'	'
Long-term debt	$5,700	'

Condensed_Consolidating_Financ3

Condensed Consolidating Financial Information (Statements of Operations) (Details 2) (USD $)

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Operating Revenues

'

'

'

'

'

'

'

'

'

'

'

Total operating revenues

$2,795

$3,490

$2,930

$2,081

$2,063

$2,331

$2,166

$1,862

$11,295

$8,422

$9,079

Operating Costs and Expenses

'

'

'

'

'

'

'

'

'

'

'

Cost of operations

'

'

'

'

'

'

'

'

8,121

6,140

6,745

Depreciation and amortization

'

'

'

'

'

'

'

'

1,256

950

896

Impairment losses

'

'

'

'

'

'

'

'

459

0

160

Selling, general and administrative

'

'

'

'

'

'

'

'

904

807

586

Acquisition related transactions and integration costs

'

'

'

'

'

'

'

'

128

107

'

Development activity expenses

'

'

'

'

'

'

'

'

84

68

57

Total operating costs and expenses

'

'

'

'

'

'

'

'

10,952

8,072

8,444

Operating Income/(Loss)

-205

527

287

-266

37

86

397

-170

343

350

635

Other Income/(Expense)

'

'

'

'

'

'

'

'

'

'

'

Equity in earnings/(losses) of consolidated subsidiaries

'

'

'

'

'

'

'

'

0

0

0

Equity in earnings of unconsolidated affiliates

'

'

'

'

'

'

'

'

7

37

35

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

0

296

0

Impairment losses on investments

'

'

'

'

'

'

'

'

-99

-2

-495

Other income, net

'

'

'

'

'

'

'

'

13

19

19

Loss on debt extinguishment

'

'

'

'

'

'

'

'

-50

-51

-175

Interest expense

'

'

'

'

'

'

'

'

-848

-661

-665

Total other income/(expense)

'

'

'

'

'

'

'

'

-977

-362

-1,281

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-634

-12

-646

Income tax benefit

'

'

'

'

'

'

'

'

-282

-327

-843

Net (Loss)/Income

'

'

'

'

'

'

'

'

-352

315

197

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

34

20

0

Net income/(loss) attributable to NRG Energy, Inc.

-290

116

122

-334

252

-1

251

-207

-386

295

197

Guarantor Subsidiaries

'

'

'

'

'

'

'

'

'

'

'

Operating Revenues

'

'

'

'

'

'

'

'

'

'

'

Total operating revenues

'

'

'

'

'

'

'

'

8,223

7,998

8,730

Operating Costs and Expenses

'

'

'

'

'

'

'

'

'

'

'

Cost of operations

'

'

'

'

'

'

'

'

6,150

5,916

6,489

Depreciation and amortization

'

'

'

'

'

'

'

'

837

860

843

Impairment losses

'

'

'

'

'

'

'

'

459

'

160

Selling, general and administrative

'

'

'

'

'

'

'

'

446

466

334

Acquisition related transactions and integration costs

'

'

'

'

'

'

'

'

0

0

'

Development activity expenses

'

'

'

'

'

'

'

'

0

0

0

Total operating costs and expenses

'

'

'

'

'

'

'

'

7,892

7,242

7,826

Operating Income/(Loss)

'

'

'

'

'

'

'

'

331

756

904

Other Income/(Expense)

'

'

'

'

'

'

'

'

'

'

'

Equity in earnings/(losses) of consolidated subsidiaries

'

'

'

'

'

'

'

'

-67

30

24

Equity in earnings of unconsolidated affiliates

'

'

'

'

'

'

'

'

-11

8

10

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

'

Impairment losses on investments

'

'

'

'

'

'

'

'

0

-2

-495

Other income, net

'

'

'

'

'

'

'

'

6

6

2

Loss on debt extinguishment

'

'

'

'

'

'

'

'

'

0

0

Interest expense

'

'

'

'

'

'

'

'

-24

-26

-59

Total other income/(expense)

'

'

'

'

'

'

'

'

-96

16

-518

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

235

772

386

Income tax benefit

'

'

'

'

'

'

'

'

114

237

-214

Net (Loss)/Income

'

'

'

'

'

'

'

'

121

535

600

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

0

0

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

121

535

600

Non-Guarantor Subsidiaries

'

'

'

'

'

'

'

'

'

'

'

Operating Revenues

'

'

'

'

'

'

'

'

'

'

'

Total operating revenues

'

'

'

'

'

'

'

'

3,211

509

381

Operating Costs and Expenses

'

'

'

'

'

'

'

'

'

'

'

Cost of operations

'

'

'

'

'

'

'

'

2,104

300

277

Depreciation and amortization

'

'

'

'

'

'

'

'

407

79

40

Impairment losses

'

'

'

'

'

'

'

'

0

'

0

Selling, general and administrative

'

'

'

'

'

'

'

'

230

45

4

Acquisition related transactions and integration costs

'

'

'

'

'

'

'

'

70

53

'

Development activity expenses

'

'

'

'

'

'

'

'

34

32

11

Total operating costs and expenses

'

'

'

'

'

'

'

'

2,845

509

332

Operating Income/(Loss)

'

'

'

'

'

'

'

'

366

0

49

Other Income/(Expense)

'

'

'

'

'

'

'

'

'

'

'

Equity in earnings/(losses) of consolidated subsidiaries

'

'

'

'

'

'

'

'

-14

-15

-7

Equity in earnings of unconsolidated affiliates

'

'

'

'

'

'

'

'

22

31

25

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

'

Impairment losses on investments

'

'

'

'

'

'

'

'

-99

0

0

Other income, net

'

'

'

'

'

'

'

'

11

6

13

Loss on debt extinguishment

'

'

'

'

'

'

'

'

-12

0

0

Interest expense

'

'

'

'

'

'

'

'

-318

-90

-56

Total other income/(expense)

'

'

'

'

'

'

'

'

-410

-68

-25

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-44

-68

24

Income tax benefit

'

'

'

'

'

'

'

'

-89

-188

7

Net (Loss)/Income

'

'

'

'

'

'

'

'

45

120

17

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

27

20

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

18

100

17

NRG Energy, Inc.

'

'

'

'

'

'

'

'

'

'

'

Operating Revenues

'

'

'

'

'

'

'

'

'

'

'

Total operating revenues

'

'

'

'

'

'

'

'

0

0

0

Operating Costs and Expenses

'

'

'

'

'

'

'

'

'

'

'

Cost of operations

'

'

'

'

'

'

'

'

0

0

0

Depreciation and amortization

'

'

'

'

'

'

'

'

12

11

13

Impairment losses

'

'

'

'

'

'

'

'

0

'

0

Selling, general and administrative

'

'

'

'

'

'

'

'

234

307

252

Acquisition related transactions and integration costs

'

'

'

'

'

'

'

'

58

54

'

Development activity expenses

'

'

'

'

'

'

'

'

50

36

46

Total operating costs and expenses

'

'

'

'

'

'

'

'

354

408

311

Operating Income/(Loss)

'

'

'

'

'

'

'

'

-354

-408

-311

Other Income/(Expense)

'

'

'

'

'

'

'

'

'

'

'

Equity in earnings/(losses) of consolidated subsidiaries

'

'

'

'

'

'

'

'

221

620

593

Equity in earnings of unconsolidated affiliates

'

'

'

'

'

'

'

'

0

-2

0

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

296

'

Impairment losses on investments

'

'

'

'

'

'

'

'

'

0

0

Other income, net

'

'

'

'

'

'

'

'

-2

9

4

Loss on debt extinguishment

'

'

'

'

'

'

'

'

-38

-51

-175

Interest expense

'

'

'

'

'

'

'

'

-506

-545

-550

Total other income/(expense)

'

'

'

'

'

'

'

'

-325

327

-128

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-679

-81

-439

Income tax benefit

'

'

'

'

'

'

'

'

-307

-376

-636

Net (Loss)/Income

'

'

'

'

'

'

'

'

-372

295

197

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

13

0

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

-385

295

197

Eliminations

'

'

'

'

'

'

'

'

'

'

'

Operating Revenues

'

'

'

'

'

'

'

'

'

'

'

Total operating revenues

'

'

'

'

'

'

'

'

-139

[1]

-85

[1]

-32

[1]

Operating Costs and Expenses

'

'

'

'

'

'

'

'

'

'

'

Cost of operations

'

'

'

'

'

'

'

'

-133

[1]

-76

[1]

-21

[1]

Depreciation and amortization

'

'

'

'

'

'

'

'

'

[1]

0

[1]

0

[1]

Impairment losses

'

'

'

'

'

'

'

'

0

[1]

'

0

[1]

Selling, general and administrative

'

'

'

'

'

'

'

'

-6

[1]

-11

[1]

-4

[1]

Acquisition related transactions and integration costs

'

'

'

'

'

'

'

'

0

[1]

0

[1]

'

Development activity expenses

'

'

'

'

'

'

'

'

0

[1]

0

[1]

0

[1]

Total operating costs and expenses

'

'

'

'

'

'

'

'

-139

[1]

-87

[1]

-25

[1]

Operating Income/(Loss)

'

'

'

'

'

'

'

'

0

[1]

2

[1]

-7

[1]

Other Income/(Expense)

'

'

'

'

'

'

'

'

'

'

'

Equity in earnings/(losses) of consolidated subsidiaries

'

'

'

'

'

'

'

'

-140

[1]

-635

[1]

-610

[1]

Equity in earnings of unconsolidated affiliates

'

'

'

'

'

'

'

'

-4

[1]

0

[1]

0

[1]

Bargain purchase gain related to GenOn acquisition

'

'

'

'

'

'

'

'

'

0

[1]

'

Impairment losses on investments

'

'

'

'

'

'

'

'

0

[1]

0

[1]

0

[1]

Other income, net

'

'

'

'

'

'

'

'

-2

[1]

-2

[1]

0

[1]

Loss on debt extinguishment

'

'

'

'

'

'

'

'

0

[1]

0

[1]

0

[1]

Interest expense

'

'

'

'

'

'

'

'

0

[1]

0

[1]

0

[1]

Total other income/(expense)

'

'

'

'

'

'

'

'

-146

[1]

-637

[1]

-610

[1]

Income/(loss) before income taxes

'

'

'

'

'

'

'

'

-146

[1]

-635

[1]

-617

[1]

Income tax benefit

'

'

'

'

'

'

'

'

0

[1]

0

[1]

0

[1]

Net (Loss)/Income

'

'

'

'

'

'

'

'

-146

[1]

-635

[1]

-617

[1]

Less: Net income attributable to noncontrolling interest

'

'

'

'

'

'

'

'

-6

[1]

0

[1]

'

Net income/(loss) attributable to NRG Energy, Inc.

'

'

'

'

'

'

'

'

($140)

[1]

($635)

[1]

($617)

[1]

[1]

All significant intercompany transactions have been eliminated in consolidation.

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Information (Statements of Comprehensive Income) (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Net (Loss)/Income	($352)		$315		$197
Unrealized loss on derivatives, net	8		-163		-309
Foreign currency translation adjustments, net	-24		-1		-2
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax	0		-11		0
Available-for-sale securities, net	3		3		-1
Defined benefit plan, net	168		-52		-46
Other comprehensive income/(loss)	155		-224		-358
Comprehensive income/(loss)	-197		91		-161
Less: Comprehensive income/(loss) attributable to noncontrolling interest	34		20		0
Comprehensive income/(loss) attributable to NRG Energy, Inc.	-231		71		-161
Dividends for preferred shares	9		9		9
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders	-240		62		-170
Guarantor Subsidiaries	'		'		'
Net (Loss)/Income	121		535		600
Unrealized loss on derivatives, net	-71		-160		-303
Foreign currency translation adjustments, net	0		0		0
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax	'		0		'
Available-for-sale securities, net	0		0		0
Defined benefit plan, net	75		-38		-34
Other comprehensive income/(loss)	4		-198		-337
Comprehensive income/(loss)	125		337		'
Less: Comprehensive income/(loss) attributable to noncontrolling interest	0		0		'
Comprehensive income/(loss) attributable to NRG Energy, Inc.	125		337		263
Dividends for preferred shares	0		0		0
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders	125		337		263
Non-Guarantor Subsidiaries	'		'		'
Net (Loss)/Income	45		120		17
Unrealized loss on derivatives, net	50		-30		-27
Foreign currency translation adjustments, net	-20		-2		-2
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax	'		11		'
Available-for-sale securities, net	0		0		0
Defined benefit plan, net	63		0		0
Other comprehensive income/(loss)	93		-43		-29
Comprehensive income/(loss)	138		77		'
Less: Comprehensive income/(loss) attributable to noncontrolling interest	27		20		'
Comprehensive income/(loss) attributable to NRG Energy, Inc.	111		57		-12
Dividends for preferred shares	0		0		0
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders	111		57		-12
NRG Energy, Inc.	'		'		'
Net (Loss)/Income	-372		295		197
Unrealized loss on derivatives, net	120		-214		-345
Foreign currency translation adjustments, net	-4		1		0
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax	'		0		'
Available-for-sale securities, net	3		3		-1
Defined benefit plan, net	30		-14		-12
Other comprehensive income/(loss)	149		-224		-358
Comprehensive income/(loss)	-223		71		'
Less: Comprehensive income/(loss) attributable to noncontrolling interest	13		0		'
Comprehensive income/(loss) attributable to NRG Energy, Inc.	-236		71		-161
Dividends for preferred shares	9		9		9
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders	-245		62		-170
Eliminations	'		'		'
Net (Loss)/Income	-146	[1]	-635	[1]	-617	[1]
Unrealized loss on derivatives, net	-91	[1]	241	[1]	366	[1]
Foreign currency translation adjustments, net	0	[1]	0	[1]	0	[1]
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax	'		0	[1]	'
Available-for-sale securities, net	0	[1]	0	[1]	0	[1]
Defined benefit plan, net	0	[1]	0	[1]	0	[1]
Other comprehensive income/(loss)	-91	[1]	241	[1]	366	[1]
Comprehensive income/(loss)	-237	[1]	-394	[1]	'
Less: Comprehensive income/(loss) attributable to noncontrolling interest	-6	[1]	0	[1]	'
Comprehensive income/(loss) attributable to NRG Energy, Inc.	-231	[1]	-394	[1]	-251	[1]
Dividends for preferred shares	0	[1]	0	[1]	0	[1]
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders	($231)	[1]	($394)	[1]	($251)	[1]
[1]	All significant intercompany transactions have been eliminated in consolidation.

Condensed_Consolidating_Financ5

Condensed Consolidating Financial Information (Balance Sheets) (Details 4) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
In Millions, unless otherwise specified
Current Assets	'		'		'		'
Cash and cash equivalents	$2,254		$2,087		$1,105		$2,951
Funds deposited by counterparties	63		271		'		'
Restricted cash	268		217		'		'
Accounts receivable - trade, net	1,214		1,061		'		'
Inventory	898		903		'		'
Derivative instruments	1,328		2,644		'		'
Deferred income taxes	258		56		'		'
Cash collateral paid in support of energy risk management activities	276		229		'		'
Renewable energy grant receivable	539		58		'		'
Prepayments and other current assets	498		446		'		'
Total current assets	-7,596		-7,972		'		'
Net Property, Plant and Equipment	19,851		20,153		'		'
Other Assets	'		'		'		'
Investment in subsidiaries	0		0		'		'
Equity investments in affiliates	453		676		'		'
Notes receivable, less current portion	73		79		'		'
Goodwill	1,985		1,956		'		'
Intangible assets, net	1,140		1,210		'		'
Nuclear decommissioning trust fund	551		473		'		'
Deferred income taxes	1,202		1,203		'		'
Derivative instruments	311		662		'		'
Other non-current assets	740		599		'		'
Total other assets	6,455		6,858		'		'
Total assets	33,902		34,983		'		'
Current Liabilities	'		'		'		'
Current portion of long-term debt and capital leases	1,050		147		'		'
Accounts payable	1,038		1,172		'		'
Accounts payable - affiliate	0		0		'		'
Derivative instruments	1,055		1,981		'		'
Deferred Tax Liabilities, Net, Current	0		'		'		'
Cash collateral received in support of energy risk management activities	63		271		'		'
Accrued expenses and other current liabilities	'		1,099		'		'
Other accrued expenses	480		539		'		'
Accounts Payable and Other Accrued Liabilities	998		'		'		'
Total current liabilities	4,204		4,670		'		'
Other Liabilities	'		'		'		'
Long-term debt and capital leases	15,767		15,736		'		'
Nuclear decommissioning reserve	294		354		'		'
Nuclear decommissioning trust liability	324		273		'		'
Postretirement and other benefit obligations	506		803		'		'
Deferred income taxes	22		55		'		'
Derivative instruments	195		500		'		'
Out-of-market contracts	1,177		1,278		'		'
Other non-current liabilities	695		796		'		'
Total non-current liabilities	18,980		19,795		'		'
Total liabilities	23,184		24,465		'		'
3.625% Preferred Stock	249		249		'		'
Stockholders' Equity	10,469		10,269		7,669		8,072
Total Liabilities and Stockholders' Equity	33,902		34,983		'		'
Guarantor Subsidiaries	'		'		'		'
Current Assets	'		'		'		'
Cash and cash equivalents	56		78		44		168
Funds deposited by counterparties	7		131		'		'
Restricted cash	12		11		'		'
Accounts receivable - trade, net	965		807		'		'
Inventory	436		472		'		'
Derivative instruments	866		2,058		'		'
Deferred income taxes	0		-153		'		'
Cash collateral paid in support of energy risk management activities	214		81		'		'
Renewable energy grant receivable	0		0		'		'
Prepayments and other current assets	4,778		2,966		'		'
Total current assets	-7,334		-6,451		'		'
Net Property, Plant and Equipment	9,116		9,905		'		'
Other Assets	'		'		'		'
Investment in subsidiaries	32		244		'		'
Equity investments in affiliates	-30		33		'		'
Notes receivable, less current portion	0		3		'		'
Goodwill	1,973		1,944		'		'
Intangible assets, net	925		1,042		'		'
Nuclear decommissioning trust fund	551		473		'		'
Deferred income taxes	0		-915		'		'
Derivative instruments	110		149		'		'
Other non-current assets	76		85		'		'
Total other assets	3,637		3,058		'		'
Total assets	20,087		19,414		'		'
Current Liabilities	'		'		'		'
Current portion of long-term debt and capital leases	1		1		'		'
Accounts payable	652		541		'		'
Accounts payable - affiliate	1,350		-55		'		'
Derivative instruments	859		1,726		'		'
Deferred Tax Liabilities, Net, Current	0		'		'		'
Cash collateral received in support of energy risk management activities	6		131		'		'
Accrued expenses and other current liabilities	'		354		'		'
Other accrued expenses	297		'		'		'
Total current liabilities	3,165		2,698		'		'
Other Liabilities	'		'		'		'
Long-term debt and capital leases	317		310		'		'
Nuclear decommissioning reserve	294		354		'		'
Nuclear decommissioning trust liability	324		273		'		'
Postretirement and other benefit obligations	218		431		'		'
Deferred income taxes	1,024		0		'		'
Derivative instruments	147		312		'		'
Out-of-market contracts	127		180		'		'
Other non-current liabilities	194		187		'		'
Total non-current liabilities	2,645		2,047		'		'
Total liabilities	5,810		4,745		'		'
3.625% Preferred Stock	'		0		'		'
Stockholders' Equity	14,277		14,669		'		'
Total Liabilities and Stockholders' Equity	20,087		19,414		'		'
Non-Guarantor Subsidiaries	'		'		'		'
Current Assets	'		'		'		'
Cash and cash equivalents	870		1,258		85		111
Funds deposited by counterparties	56		140		'		'
Restricted cash	252		196		'		'
Accounts receivable - trade, net	249		254		'		'
Inventory	462		431		'		'
Derivative instruments	470		604		'		'
Deferred income taxes	41		10		'		'
Cash collateral paid in support of energy risk management activities	62		148		'		'
Renewable energy grant receivable	539		58		'		'
Prepayments and other current assets	379		-12		'		'
Total current assets	-3,380		-3,087		'		'
Net Property, Plant and Equipment	10,604		10,147		'		'
Other Assets	'		'		'		'
Investment in subsidiaries	422		-102		'		'
Equity investments in affiliates	583		633		'		'
Notes receivable, less current portion	62		74		'		'
Goodwill	12		12		'		'
Intangible assets, net	232		187		'		'
Nuclear decommissioning trust fund	'		0		'		'
Deferred income taxes	681		1,886		'		'
Derivative instruments	202		515		'		'
Other non-current assets	281		304		'		'
Total other assets	2,475		3,509		'		'
Total assets	16,459		16,743		'		'
Current Liabilities	'		'		'		'
Current portion of long-term debt and capital leases	1,029		137		'		'
Accounts payable	352		585		'		'
Accounts payable - affiliate	760		1,421		'		'
Derivative instruments	204		271		'		'
Deferred Tax Liabilities, Net, Current	0		'		'		'
Cash collateral received in support of energy risk management activities	57		140		'		'
Accrued expenses and other current liabilities	'		502		'		'
Other accrued expenses	410		'		'		'
Total current liabilities	2,812		3,056		'		'
Other Liabilities	'		'		'		'
Long-term debt and capital leases	7,837		8,459		'		'
Nuclear decommissioning reserve	0		0		'		'
Nuclear decommissioning trust liability	0		0		'		'
Postretirement and other benefit obligations	194		326		'		'
Deferred income taxes	-1,002		0		'		'
Derivative instruments	49		190		'		'
Out-of-market contracts	1,050		1,129		'		'
Other non-current liabilities	421		520		'		'
Total non-current liabilities	8,549		10,624		'		'
Total liabilities	11,361		13,680		'		'
3.625% Preferred Stock	'		0		'		'
Stockholders' Equity	5,098		3,063		'		'
Total Liabilities and Stockholders' Equity	16,459		16,743		'		'
NRG Energy, Inc.	'		'		'		'
Current Assets	'		'		'		'
Cash and cash equivalents	1,328		751		976		2,672
Funds deposited by counterparties	0		0		'		'
Restricted cash	4		10		'		'
Accounts receivable - trade, net	0		0		'		'
Inventory	0		0		'		'
Derivative instruments	0		0		'		'
Deferred income taxes	217		199		'		'
Cash collateral paid in support of energy risk management activities	0		0		'		'
Renewable energy grant receivable	0		0		'		'
Prepayments and other current assets	-3,802		-2,518		'		'
Total current assets	-2,253		-1,558		'		'
Net Property, Plant and Equipment	153		121		'		'
Other Assets	'		'		'		'
Investment in subsidiaries	18,266		17,565		'		'
Equity investments in affiliates	'		10		'		'
Notes receivable, less current portion	105		531		'		'
Goodwill	0		0		'		'
Intangible assets, net	4		33		'		'
Nuclear decommissioning trust fund	0		0		'		'
Deferred income taxes	521		232		'		'
Derivative instruments	0		0		'		'
Other non-current assets	383		210		'		'
Total other assets	19,279		18,581		'		'
Total assets	17,179		17,144		'		'
Current Liabilities	'		'		'		'
Current portion of long-term debt and capital leases	20		15		'		'
Accounts payable	34		46		'		'
Accounts payable - affiliate	-1,253		-1,366		'		'
Derivative instruments	0		2		'		'
Deferred Tax Liabilities, Net, Current	0		'		'		'
Cash collateral received in support of energy risk management activities	0		0		'		'
Accrued expenses and other current liabilities	'		243		'		'
Other accrued expenses	291		'		'		'
Total current liabilities	-908		-1,060		'		'
Other Liabilities	'		'		'		'
Long-term debt and capital leases	7,707		7,496		'		'
Nuclear decommissioning reserve	0		0		'		'
Nuclear decommissioning trust liability	0		0		'		'
Postretirement and other benefit obligations	94		46		'		'
Deferred income taxes	0		55		'		'
Derivative instruments	0		0		'		'
Out-of-market contracts	0		0		'		'
Other non-current liabilities	80		89		'		'
Total non-current liabilities	7,881		7,686		'		'
Total liabilities	6,973		6,626		'		'
3.625% Preferred Stock	249		249		'		'
Stockholders' Equity	9,957		10,269		'		'
Total Liabilities and Stockholders' Equity	17,179		17,144		'		'
Eliminations	'		'		'		'
Current Assets	'		'		'		'
Cash and cash equivalents	0	[1]	0	[1]	0	[1]	0	[1]
Funds deposited by counterparties	0	[1]	0	[1]	'		'
Restricted cash	0	[1]	0	[1]	'		'
Accounts receivable - trade, net	0	[1]	0	[1]	'		'
Inventory	0	[1]	0	[1]	'		'
Derivative instruments	-8	[1]	-18	[1]	'		'
Deferred income taxes	0	[1]	0	[1]	'		'
Cash collateral paid in support of energy risk management activities	0	[1]	0	[1]	'		'
Renewable energy grant receivable	0	[1]	0		'		'
Prepayments and other current assets	-857	[1]	10	[1]	'		'
Total current assets	865	[1]	8	[1]	'		'
Net Property, Plant and Equipment	-22	[1]	-20	[1]	'		'
Other Assets	'		'		'		'
Investment in subsidiaries	-18,720	[1]	-17,707	[1]	'		'
Equity investments in affiliates	-100	[1]	0	[1]	'		'
Notes receivable, less current portion	-94	[1]	-529	[1]	'		'
Goodwill	0	[1]	0	[1]	'		'
Intangible assets, net	-21	[1]	-52	[1]	'		'
Nuclear decommissioning trust fund	0	[1]	0	[1]	'		'
Deferred income taxes	0	[1]	0	[1]	'		'
Derivative instruments	-1	[1]	-2	[1]	'		'
Other non-current assets	0	[1]	0	[1]	'		'
Total other assets	-18,936	[1]	-18,290	[1]	'		'
Total assets	-19,823	[1]	-18,318	[1]	'		'
Current Liabilities	'		'		'		'
Current portion of long-term debt and capital leases	0	[1]	-6	[1]	'		'
Accounts payable	0	[1]	0	[1]	'		'
Accounts payable - affiliate	-857	[1]	0	[1]	'		'
Derivative instruments	-8	[1]	-18	[1]	'		'
Deferred Tax Liabilities, Net, Current	0		'		'		'
Cash collateral received in support of energy risk management activities	0	[1]	0	[1]	'		'
Accrued expenses and other current liabilities	'		0	[1]	'		'
Other accrued expenses	0	[1]	'		'		'
Total current liabilities	-865	[1]	-24	[1]	'		'
Other Liabilities	'		'		'		'
Long-term debt and capital leases	-94	[1]	-529	[1]	'		'
Nuclear decommissioning reserve	0	[1]	0	[1]	'		'
Nuclear decommissioning trust liability	0	[1]	0	[1]	'		'
Postretirement and other benefit obligations	0	[1]	0	[1]	'		'
Deferred income taxes	0	[1]	0	[1]	'		'
Derivative instruments	-1	[1]	-2	[1]	'		'
Out-of-market contracts	0	[1]	-31	[1]	'		'
Other non-current liabilities	0	[1]	0	[1]	'		'
Total non-current liabilities	-95	[1]	-562	[1]	'		'
Total liabilities	-960	[1]	-586	[1]	'		'
3.625% Preferred Stock	'	[1]	0	[1]	'		'
Stockholders' Equity	-18,863	[1]	-17,732	[1]	'		'
Total Liabilities and Stockholders' Equity	($19,823)	[1]	($18,318)	[1]	'		'
[1]	All significant intercompany transactions have been eliminated in consolidation.

Condensed_Consolidating_Financ6

Condensed Consolidating Financial Information (Statements of Cash Flows) (Details 5) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Cash Flows from Operating Activities	'		'		'
Net (Loss)/Income	($352)		$315		$197
Adjustments to reconcile net income to net cash provided/(used) by operating activities:	'		'		'
Distributions and equity in earnings of unconsolidated affiliates and consolidated subsidiaries	84		2		9
Bargain purchase gain related to GenOn acquisition	0		-296		0
Depreciation and amortization	1,256		950		896
Provision for bad debts	67		45		59
Amortization of nuclear fuel	36		39		39
Amortization of financing costs and debt discount/premiums	33		31		32
Adjustment to loss on debt extinguishment	-15		9		58
Amortization of intangibles and out-of-market commodity contracts	-49		-146		-167
Changes in deferred income taxes and liability for uncertain tax benefits	-67		-353		-859
Changes in nuclear decommissioning trust liability	15		37		20
Impairment losses	558		0		657
Loss/(gain) on disposals and sales of assets	-3		11		14
Amortization of unearned equity compensation	38		41		28
Net Cash Provided by Operating Activities	1,270		1,149		1,166
Cash Flows from Investing Activities	'		'		'
Intercompany (loans to)/receipts from subsidiaries	0		0		0
Investment in subsidiaries	'		'		0
Acquisition of businesses, net of cash acquired	-494		-81		-377
Cash acquired in GenOn acquisition	0		983		0
Capital expenditures	-1,987		-3,396		-2,310
Increase in restricted cash, net	-22		-66		-35
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects	-26		164		-215
(Increase)/decrease in notes receivable	-11		-24		12
Purchases of emission allowances, net of proceeds	5		1		19
Investments in nuclear decommissioning trust fund securities	-514		-436		-406
Proceeds from sales of nuclear decommissioning trust fund securities	488		399		385
Proceeds from renewable energy grants	55		62		0
Proceeds/(purchases) from sale of assets, net	13		137		7
(Investments in)/proceeds from sales of unconsolidated affiliates, net	0		-25		-66
Other	-35		22		-23
Net Cash Used by Investing Activities	-2,528		-2,262		-3,047
Cash Flows from Financing Activities	'		'		'
(Payments)/proceeds from intercompany loans	0		0		0
Payment of dividends to preferred and common stockholders	-154		-50		-9
Payment of intercompany dividends	0		0		0
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements	267		-68		-83
Payment for treasury stock	-25		0		-430
Proceeds from issuance of long-term debt	1,777		3,165		6,224
Payments for term loan for funded letter of credit facility	0		0		1,300
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	531		347		29
Proceeds from issuance of common stock, net of issuance costs	16		0		2
Decrease in restricted cash supporting funded letter of credit facility	0		0		-1,300
Payment of debt issuance and hedging costs	-50		-35		-207
Payments for short and long-term debt	-935		-1,260		-5,493
Net Cash Provided by Financing Activities	1,427		2,099		33
Effect of exchange rate changes on cash and cash equivalents	-2		-4		2
Net Increase/(Decrease) in Cash and Cash Equivalents	167		982		-1,846
Cash and Cash Equivalents at Beginning of Period	2,087		1,105		2,951
Cash and Cash Equivalents at End of Period	2,254		2,087		1,105
Guarantor Subsidiaries	'		'		'
Cash Flows from Operating Activities	'		'		'
Net (Loss)/Income	121		535		600
Adjustments to reconcile net income to net cash provided/(used) by operating activities:	'		'		'
Bargain purchase gain related to GenOn acquisition	'		0		'
Depreciation and amortization	837		860		843
Net Cash Provided by Operating Activities	2,318		2,163		621
Cash Flows from Investing Activities	'		'		'
Intercompany (loans to)/receipts from subsidiaries	-1,722		-1,792		796
Investment in subsidiaries	'		'		0
Acquisition of businesses, net of cash acquired	'		0		0
Cash acquired in GenOn acquisition	'		0		'
Capital expenditures	-528		-241		-383
Increase in restricted cash, net	-1		-3		-5
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects	'		0		0
(Increase)/decrease in notes receivable	2		-1		0
Purchases of emission allowances, net of proceeds	5		1		19
Investments in nuclear decommissioning trust fund securities	-514		-436		-406
Proceeds from sales of nuclear decommissioning trust fund securities	488		399		385
Proceeds from renewable energy grants	'		3		'
Proceeds/(purchases) from sale of assets, net	13		133		13
(Investments in)/proceeds from sales of unconsolidated affiliates, net	'		-1		-2
Other	-4		24		-2
Net Cash Used by Investing Activities	-2,261		-1,916		377
Cash Flows from Financing Activities	'		'		'
(Payments)/proceeds from intercompany loans	0		0		-1,112
Payment of dividends to preferred and common stockholders	'		0		0
Payment of intercompany dividends	0		-172		-65
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements	-79		-83		-83
Payment for treasury stock	0		'		0
Proceeds from issuance of long-term debt	0		42		138
Payments for term loan for funded letter of credit facility	'		'		0
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	0		0		'
Proceeds from issuance of common stock, net of issuance costs	0		'		0
Decrease in restricted cash supporting funded letter of credit facility	'		'		0
Payment of debt issuance and hedging costs	0		0		0
Payments for short and long-term debt	0		0		0
Net Cash Provided by Financing Activities	-79		-213		-1,122
Effect of exchange rate changes on cash and cash equivalents	0		0		0
Net Increase/(Decrease) in Cash and Cash Equivalents	-22		34		-124
Cash and Cash Equivalents at Beginning of Period	78		44		168
Cash and Cash Equivalents at End of Period	56		78		44
Non-Guarantor Subsidiaries	'		'		'
Cash Flows from Operating Activities	'		'		'
Net (Loss)/Income	45		120		17
Adjustments to reconcile net income to net cash provided/(used) by operating activities:	'		'		'
Bargain purchase gain related to GenOn acquisition	'		0		'
Depreciation and amortization	407		79		40
Net Cash Provided by Operating Activities	-217		66		294
Cash Flows from Investing Activities	'		'		'
Intercompany (loans to)/receipts from subsidiaries	7		792		0
Investment in subsidiaries	'		'		-1,300
Acquisition of businesses, net of cash acquired	-179		-17		-115
Cash acquired in GenOn acquisition	'		983		'
Capital expenditures	-1,413		-3,091		-1,882
Increase in restricted cash, net	-22		-63		-29
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects	-31		121		-162
(Increase)/decrease in notes receivable	-7		-21		12
Purchases of emission allowances, net of proceeds	0		0		0
Investments in nuclear decommissioning trust fund securities	0		0		0
Proceeds from sales of nuclear decommissioning trust fund securities	0		0		0
Proceeds from renewable energy grants	55		59		'
Proceeds/(purchases) from sale of assets, net	0		0		-6
(Investments in)/proceeds from sales of unconsolidated affiliates, net	'		-12		-64
Other	-11		0		-8
Net Cash Used by Investing Activities	-1,601		-1,249		-3,554
Cash Flows from Financing Activities	'		'		'
(Payments)/proceeds from intercompany loans	0		0		825
Payment of dividends to preferred and common stockholders	'		0		0
Payment of intercompany dividends	0		-6		-4
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements	346		15		0
Payment for treasury stock	0		'		0
Proceeds from issuance of long-term debt	1,292		2,105		1,290
Payments for term loan for funded letter of credit facility	'		'		1,300
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	531		347		'
Proceeds from issuance of common stock, net of issuance costs	0		'		0
Decrease in restricted cash supporting funded letter of credit facility	'		'		0
Payment of debt issuance and hedging costs	-21		-19		-92
Payments for short and long-term debt	-716		-82		-116
Net Cash Provided by Financing Activities	1,432		2,360		3,232
Effect of exchange rate changes on cash and cash equivalents	-2		-4		2
Net Increase/(Decrease) in Cash and Cash Equivalents	-388		1,173		-26
Cash and Cash Equivalents at Beginning of Period	1,258		85		111
Cash and Cash Equivalents at End of Period	870		1,258		85
NRG Energy, Inc.	'		'		'
Cash Flows from Operating Activities	'		'		'
Net (Loss)/Income	-372		295		197
Adjustments to reconcile net income to net cash provided/(used) by operating activities:	'		'		'
Bargain purchase gain related to GenOn acquisition	'		-296		'
Depreciation and amortization	12		11		13
Net Cash Provided by Operating Activities	-2,546		-902		1,620
Cash Flows from Investing Activities	'		'		'
Intercompany (loans to)/receipts from subsidiaries	1,715		0		287
Investment in subsidiaries	'		'		0
Acquisition of businesses, net of cash acquired	-315		-64		-262
Cash acquired in GenOn acquisition	'		0		'
Capital expenditures	-46		-64		-45
Increase in restricted cash, net	1		0		-1
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects	5		43		-53
(Increase)/decrease in notes receivable	-6		-2		0
Purchases of emission allowances, net of proceeds	0		0		0
Investments in nuclear decommissioning trust fund securities	0		0		0
Proceeds from sales of nuclear decommissioning trust fund securities	0		0		0
Proceeds from renewable energy grants	0		0		'
Proceeds/(purchases) from sale of assets, net	0		4		0
(Investments in)/proceeds from sales of unconsolidated affiliates, net	'		-12		0
Other	-20		-2		-13
Net Cash Used by Investing Activities	1,334		-97		-87
Cash Flows from Financing Activities	'		'		'
(Payments)/proceeds from intercompany loans	1,715		1,000		-796
Payment of dividends to preferred and common stockholders	-154		-50		-9
Payment of intercompany dividends	0		0		0
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements	0		0		0
Payment for treasury stock	-25		'		-430
Proceeds from issuance of long-term debt	485		1,018		4,796
Payments for term loan for funded letter of credit facility	'		'		0
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	0		0		'
Proceeds from issuance of common stock, net of issuance costs	16		'		2
Decrease in restricted cash supporting funded letter of credit facility	'		'		1,300
Payment of debt issuance and hedging costs	-29		-16		-115
Payments for short and long-term debt	-219		-1,178		-5,377
Net Cash Provided by Financing Activities	1,789		774		-3,229
Effect of exchange rate changes on cash and cash equivalents	0		0		0
Net Increase/(Decrease) in Cash and Cash Equivalents	577		-225		-1,696
Cash and Cash Equivalents at Beginning of Period	751		976		2,672
Cash and Cash Equivalents at End of Period	1,328		751		976
Eliminations	'		'		'
Cash Flows from Operating Activities	'		'		'
Net (Loss)/Income	-146	[1]	-635	[1]	-617	[1]
Adjustments to reconcile net income to net cash provided/(used) by operating activities:	'		'		'
Bargain purchase gain related to GenOn acquisition	'		0	[1]	'
Depreciation and amortization	'	[1]	0	[1]	0	[1]
Net Cash Provided by Operating Activities	1,715		-178	[1]	-1,369	[1]
Cash Flows from Investing Activities	'		'		'
Intercompany (loans to)/receipts from subsidiaries	0	[1]	1,000	[1]	-1,083	[1]
Investment in subsidiaries	'		'		1,300	[1]
Acquisition of businesses, net of cash acquired	0	[1]	0	[1]	0	[1]
Cash acquired in GenOn acquisition	'		0	[1]	'
Capital expenditures	0	[1]	0	[1]	0	[1]
Increase in restricted cash, net	0	[1]	0	[1]	0	[1]
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects	0	[1]	0	[1]	0	[1]
(Increase)/decrease in notes receivable	0	[1]	0	[1]	0	[1]
Purchases of emission allowances, net of proceeds	0	[1]	0	[1]	0	[1]
Investments in nuclear decommissioning trust fund securities	0	[1]	0	[1]	0	[1]
Proceeds from sales of nuclear decommissioning trust fund securities	0	[1]	0	[1]	0	[1]
Proceeds from renewable energy grants	0	[1]	0	[1]	'
Proceeds/(purchases) from sale of assets, net	0	[1]	0	[1]	0	[1]
(Investments in)/proceeds from sales of unconsolidated affiliates, net	'		0	[1]	0	[1]
Other	0	[1]	0	[1]	0	[1]
Net Cash Used by Investing Activities	0	[1]	1,000	[1]	217	[1]
Cash Flows from Financing Activities	'		'		'
(Payments)/proceeds from intercompany loans	-1,715	[1]	-1,000	[1]	1,083	[1]
Payment of dividends to preferred and common stockholders	0	[1]	0	[1]	0	[1]
Payment of intercompany dividends	0	[1]	178	[1]	69	[1]
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements	0	[1]	0	[1]	0	[1]
Payment for treasury stock	0		'		0	[1]
Proceeds from issuance of long-term debt	0	[1]	0	[1]	0	[1]
Payments for term loan for funded letter of credit facility	'		'		0	[1]
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	0	[1]	0	[1]	'
Proceeds from issuance of common stock, net of issuance costs	0		'		0	[1]
Decrease in restricted cash supporting funded letter of credit facility	'		'		0	[1]
Payment of debt issuance and hedging costs	0	[1]	0	[1]	0	[1]
Payments for short and long-term debt	0	[1]	0	[1]	0	[1]
Net Cash Provided by Financing Activities	-1,715	[1]	-822	[1]	1,152	[1]
Effect of exchange rate changes on cash and cash equivalents	0	[1]	0	[1]	0	[1]
Net Increase/(Decrease) in Cash and Cash Equivalents	0	[1]	0	[1]	0	[1]
Cash and Cash Equivalents at Beginning of Period	0	[1]	0	[1]	0	[1]
Cash and Cash Equivalents at End of Period	0	[1]	0	[1]	0	[1]
Installment Proceeds [Member]	'		'		'
Cash Flows from Financing Activities	'		'		'
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	'		'		29
Installment Proceeds [Member] | Guarantor Subsidiaries	'		'		'
Cash Flows from Financing Activities	'		'		'
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	'		'		0
Installment Proceeds [Member] | Non-Guarantor Subsidiaries	'		'		'
Cash Flows from Financing Activities	'		'		'
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	'		'		29
Installment Proceeds [Member] | NRG Energy, Inc.	'		'		'
Cash Flows from Financing Activities	'		'		'
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	'		'		0
Installment Proceeds [Member] | Eliminations	'		'		'
Cash Flows from Financing Activities	'		'		'
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	'		'		$0	[1]
[1]	All significant intercompany transactions have been eliminated in consolidation.

VALUATION_AND_QUALIFYING_ACCOU1

VALUATION AND QUALIFYING ACCOUNTS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Allowance for doubtful accounts, deducted from accounts receivable	'		'		'
Changes in Valuation and Qualifying Accounts	'		'		'
Balance at Beginning of Period	$32		$23		$25
Charged to Costs and Expenses	66		46		60
Charged to Other Accounts	0		0		0
Deductions	-58	[1]	-37	[1]	-62	[1]
Balance at End of Period	40		32		23
Income tax valuation allowance, deducted from deferred tax assets	'		'		'
Changes in Valuation and Qualifying Accounts	'		'		'
Balance at Beginning of Period	191		83		191
Charged to Costs and Expenses	32		5		-63
Charged to Other Accounts	68	[2]	103		-45
Deductions	0		0		0
Balance at End of Period	$291		$191		$83
[1]	Represents principally net amounts charged as uncollectible.
[2]	Text selection found with no content.