NRG Energy (NRG) 10-K 28 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	NRG ENERGY, INC.
Entity Central Index Key	1,013,871
Document Type	10-K
Document Period End Date	Dec. 31, 2016
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			$ 4,180,823,320
Entity Common Stock, Shares Outstanding		315,972,715
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues
Total operating revenues	$ 2,532	$ 3,952	$ 2,638	$ 3,229	$ 3,011	$ 4,434	$ 3,400	$ 3,829	$ 12,351	$ 14,674	$ 15,868
Operating Costs and Expenses
Cost of operations									8,555	10,784	11,808
Depreciation and amortization									1,367	1,566	1,523
Impairment losses									918	5,030	97
Selling, general and administrative									1,101	1,199	1,016
Acquisition-related transaction and integration costs									8	10	84
Research and Development Expense									90	146	88
Total operating costs and expenses									12,039	18,735	14,616
Gain on sale of assets									215	0	19
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments									0	21	0
Operating Income/(Loss)	(791)	755	87	476	(4,727)	379	232	76	527	(4,040)	1,271
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates									27	36	38
Impairment losses on investments									(268)	(56)	0
Other income, net									42	33	22
(Loss)/gain on sale of equity method investment									0	(14)	18
Gain (Loss) on Extinguishment of Debt									(142)	75	(95)
Interest expense									(1,061)	(1,128)	(1,119)
Total other expense									(1,402)	(1,054)	(1,136)
(Loss)/Income Before Income Taxes									(875)	(5,094)	135
Income tax expense									16	1,342	3
Net (Loss)/Income	(1,055)	393	(276)	47	(6,358)	67	(9)	(136)	(891)	(6,436)	132
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(68)	(9)	(5)	(35)	(44)	1	5	(16)	(117)	(54)	(2)
Net Income (Loss) Attributable to Nonredeemable Noncontrolling Interest											17
Net (Loss)/Income Attributable to NRG Energy, Inc.	(987)	402	(271)	82	(6,314)	66	(14)	(120)	(774)	(6,382)	134
Preferred Stock Dividends, Income Statement Impact									5	20	56
Gain on Redemption of Redeemable Preferred Stock			78						(78)	0	0
(Loss)/Income Available for Common Stockholders	$ (987)	$ 402	$ (193)	$ 77	$ (6,319)	$ 61	$ (19)	$ (125)	$ (701)	$ (6,402)	$ 78
(Loss)/Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	316	316	315	315	315	331	333	336	316	329	334
Net (Loss)/Income per Weighted Average Common Share — Basic	$ (3.13)	$ 1.27	$ (0.61)	$ 0.24	$ (20.08)	$ 0.18	$ (0.06)	$ 0.37	$ (2.22)	$ (19.46)	$ 0.23
Weighted average number of common shares outstanding — diluted	316	317	315	315	315	332	333	336	316	329	339
Net (Loss)/Income per Weighted Average Common Share — Diluted	$ (3.13)	$ 1.27	$ (0.61)	$ 0.24	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ (2.22)	$ (19.46)	$ 0.23
Dividends Per Common Share									$ 0.24	$ 0.58	$ 0.54

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net (Loss)/Income	$ (1,055)	$ 393	$ (276)	$ 47	$ (6,358)	$ 67	$ (9)	$ (136)	$ (891)	$ (6,436)	$ 132
Other Comprehensive Income/(Loss), net of tax
Unrealized gain/(loss) on derivatives, net of income tax expense/(benefit) of $1, $19, and $(21)									35	(15)	(45)
Foreign currency translation adjustments, net of income tax benefit of $0, $0, and $5									(1)	(11)	(8)
Available-for-sale securities, net of income tax benefit of $0, $3, and $2									1	17	(7)
Defined benefit plan, net of income tax expense/(benefit) of $0, $69, and $(88)									3	10	(129)
Other comprehensive income/(loss)									38	1	(189)
Comprehensive Loss									(853)	(6,435)	(57)
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									(117)	(73)	8
Comprehensive Loss Attributable to NRG Energy, Inc.									(736)	(6,362)	(65)
Preferred Stock Dividends, Income Statement Impact									5	20	56
Gain on Redemption of Redeemable Preferred Stock			$ 78						(78)	0	0
Comprehensive Loss Available for Common Stockholders									$ (663)	$ (6,382)	$ (121)

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Unrealized loss/gain on derivatives, income tax benefit/(expense)	$ (1)	$ (19)	$ 21
Foreign currency translation adjustments, income tax benefit/(expense)	0	0	5
Available-for-sale securities, income tax benefit/(expense)	0	3	2
Defined benefit plan, income tax benefit/(expense)	$ 0	$ (69)	$ 88

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 1,973	$ 1,518
Funds deposited by counterparties	2	106
Restricted cash	446	414
Accounts receivable — trade	1,166	1,157
Inventory	1,111	1,252
Derivative instruments	1,062	1,915
Cash collateral posted in support of energy risk management activities	203	568
Current assets held-for-sale	9	6
Prepayments and other current assets	423	455
Total current assets	6,395	7,391
Property, plant and equipment, net	17,912	18,732
Other Assets
Equity investments in affiliates	1,120	1,045
Notes receivable, less current portion	17	53
Goodwill	662	999
Intangible assets, net	2,036	2,310
Nuclear decommissioning trust fund	610	561
Derivative instruments	189	305
Deferred income taxes	225	167
Non-current assets held-for-sale	10	105
Other non-current assets	1,179	1,214
Total other assets	6,048	6,759
Total Assets	30,355	32,882
Current Liabilities
Current portion of long-term debt and capital leases	1,220	481
Accounts payable	895	869
Derivative instruments	1,084	1,721
Cash collateral received in support of energy risk management activities	2	106
Accrued interest expense	220	242
Other accrued expenses	543	568
Current liabilities held-for-sale	0	2
Other current liabilities	418	386
Total current liabilities	4,382	4,375
Other Liabilities
Long-term debt and capital leases	18,006	18,983
Nuclear decommissioning reserve	287	326
Nuclear decommissioning trust liability	339	283
Postretirement and other benefit obligations	553	588
Deferred income taxes	20	19
Derivative instruments	294	493
Non-current liabilities held-for-sale	12	4
Off-market Lease, Unfavorable	1,040	1,146
Other non-current liabilities	930	900
Total non-current liabilities	21,481	22,742
Total Liabilities	25,863	27,117
2.822% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding at December 31, 2015	0	302
Redeemable noncontrolling interest in subsidiaries	46	29
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 417,583,825 and 416,939,950 shares issued; and 315,443,011 and 314,190,042 shares outstanding at December 31, 2016 and 2015	4	4
Additional paid-in capital	8,358	8,296
Accumulated deficit	(3,787)	(3,007)
Treasury stock, at cost; 102,140,814 and 102,749,908 shares at December 31, 2016 and 2015	(2,399)	(2,413)
Accumulated other comprehensive loss	(135)	(173)
Noncontrolling interest	2,405	2,727
Total Stockholders' Equity	4,446	5,434
Total Liabilities and Stockholders' Equity	$ 30,355	$ 32,882

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
2.822% convertible perpetual preferred stock, par value (in dollars)	$ 0.01	$ 0.01
2.822% convertible perpetual preferred stock, shares issued	0	250,000
2.822% convertible perpetual preferred stock, shares outstanding	0	250,000
Common stock, par value (in dollars)	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	417,583,825	416,939,950
Common stock, shares outstanding	315,443,011	314,190,042
Treasury stock, shares	102,140,814	102,749,908
Convertible Preferred Stock [Member]
Preferred Stock, Dividend Rate Amended, Percentage	2.822%	2.822%

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities
Net (Loss)/Income	$ (891)	$ (6,436)	$ 132
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distribution of unconsolidated affiliates	54	37	49
Depreciation and amortization	1,367	1,566	1,523
Provision for bad debts	48	64	64
Amortization of nuclear fuel	49	45	46
Amortization of financing costs and debt discount/premiums	3	(11)	(12)
Adjustment to loss/(gain) on debt extinguishment	21	(75)	25
Gain (Loss) on Extinguishment of Debt	(142)	75	(95)
Amortization of intangibles and out-of-market contracts	91	81	64
Amortization of unearned equity compensation	10	41	42
Net (gain)/loss on sale of assets and equity method investments	(224)	14	(4)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	(21)	0
Impairment losses	1,186	5,086	97
Changes in derivative instruments	23	233	(61)
Changes in deferred income taxes and liability for uncertain tax benefits	(43)	1,326	(154)
Changes in Collateral Deposits Supporting Energy Risk Management Activities	365	(381)	146
Gain on sale of emissions allowances	47	0	0
Changes in nuclear decommissioning trust liability	41	(2)	19
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects:
Accounts receivable - trade	(12)	136	(2)
Inventory	134	(26)	(245)
Prepayments and other current assets	(39)	8	36
Accounts payable	(27)	(218)	(12)
Accrued expenses and other current liabilities	(39)	(9)	(26)
Other assets and liabilities	(92)	(149)	(217)
Net Cash Provided by Operating Activities	2,072	1,309	1,510
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(209)	(31)	(2,936)
Capital expenditures	(1,244)	(1,283)	(909)
(Increase)/decrease in restricted cash, net	(29)	8	57
(Increase)/decrease in restricted cash to support equity requirements for U.S. DOE funded projects	(3)	35	(206)
Increase (Decrease) in Notes Receivables	17	18	25
Proceeds from renewable energy grants	36	82	916
Purchases of emission allowances, net of proceeds	(1)	41	(16)
Investments in nuclear decommissioning trust fund securities	(551)	(629)	(619)
Proceeds from sales of nuclear decommissioning trust fund securities	510	631	600
Proceeds from sale of assets, net	636	27	203
Investments in unconsolidated affiliates	(34)	(395)	(103)
Other	48	11	85
Net Cash Used by Investing Activities	(824)	(1,485)	(2,903)
Cash Flows from Financing Activities
Payments of dividends to preferred and common stockholders	(76)	(201)	(196)
Net receipts from settlement of acquired derivatives that include financing elements	151	196	9
Payments for treasury stock	0	(437)	(39)
Payments for Repurchase of Redeemable Preferred Stock	(226)	0	0
Distributions from, net of contributions to, noncontrolling interests in subsidiaries	(156)	47	189
Proceeds from sale of noncontrolling interests in subsidiaries	0	600	630
Proceeds from issuance of common stock	1	1	21
Proceeds from issuance of long-term debt	5,527	1,004	4,563
Payments of debt issuance and hedging costs	(89)	(21)	(67)
Payments for short and long-term debt	(5,913)	(1,599)	(3,827)
Proceeds from (Payments for) Other Financing Activities	(13)	(22)	(18)
Net Cash (Used)/Provided by Financing Activities	(794)	(432)	1,265
Effect of exchange rate changes on cash and cash equivalents	1	10	(10)
Net Increase/(Decrease) in Cash and Cash Equivalents	455	(598)	(138)
Cash and Cash Equivalents at Beginning of Period	1,518	2,116	2,254
Cash and Cash Equivalents at End of Period	$ 1,973	$ 1,518	$ 2,116

Consolidated Statement of Stock

Consolidated Statement of Stockholders' Equity - USD ($) $ in Millions	Total	Common Stock	Additional Paid-In Capital	Retained Earnings/ (Accumu-lated Deficit)	Treasury Stock	Accumulated Other Comprehensive Income/(Loss)	Noncontrolling Interest	NRG Yield	NRG Yield, Inc. [Member]	NRG Yield, Inc. [Member]Noncontrolling Interest
Balance at Dec. 31, 2013	$ 10,467	$ 4	$ 7,840	$ 3,695	$ (1,942)	$ 5	$ 865
Increase (Decrease) in Stockholders' Equity
Net (loss)/income attributable to NRG Energy, Inc.	134
Net income/(loss) attributable to noncontrolling interest	17
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	151
Other Comprehensive Income (Loss), Net of Tax	(189)					(179)
Issuance of shares for acquisition of EME	401		401
Noncontrolling Interest, Increase from Business Combination	352						352
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(57)
Equity-based compensation	45		45
Purchase of treasury stock	(44)				(44)
Common stock dividends	(181)			(181)
Preferred Stock Dividends, Income Statement Impact	(56)
Redeemable Preferred Stock Dividends	9			(9)
ESPP share purchases	(1)			(4)	3
Proceeds from issuance of common stock	21		41				(41)	$ 0
Other Preferred Stock Dividends and Adjustments	(47)			47
Gain on Redemption of Redeemable Preferred Stock	0
Non-cash adjustment for issuance of convertible debt	23						23
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	630						630
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	125						125
Balance at Dec. 31, 2014	11,676	4	8,327	3,588	(1,983)	(174)	1,914
Increase (Decrease) in Stockholders' Equity
Net (loss)/income attributable to NRG Energy, Inc.	(6,382)
Net income/(loss) attributable to noncontrolling interest							(37)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	(6,419)
Other Comprehensive Income (Loss), Net of Tax	1					1
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest							(4)
Other Comprehensive Income (Loss), Including OCI for NCI	(3)
Sale of Assets Under Common Control			(56)				83	27
Noncontrolling Interest, Increase from Business Combination							74	74
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(159)
Equity-based compensation	24		26	(2)
Purchase of treasury stock	(437)				(437)
Common stock dividends	(191)			(191)
Preferred Stock Dividends, Income Statement Impact	(20)			20
ESPP share purchases	6		(1)		7
Noncontrolling Interest, Contributions from Noncontrolling Interest Holders	234						234
Proceeds from issuance of common stock	1
Other Preferred Stock Dividends and Adjustments	0
Gain on Redemption of Redeemable Preferred Stock	0
Non-cash adjustment for issuance of convertible debt	23						23
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	599						599
Balance at Dec. 31, 2015	5,434	4	8,296	(3,007)	(2,413)	(173)	2,727
Increase (Decrease) in Stockholders' Equity
Net (loss)/income attributable to NRG Energy, Inc.	(774)
Net income/(loss) attributable to noncontrolling interest							(79)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	(853)
Other Comprehensive Income (Loss), Net of Tax	38					38
Other Comprehensive Income (Loss), Including OCI for NCI	38
Sale of Assets Under Common Control			59				(16)	$ 43
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(158)						(158)		$ (92)	$ (92)
Equity-based compensation	6		5	1
Common stock dividends	(74)			(74)
Preferred Stock Dividends, Income Statement Impact	(5)			5
ESPP share purchases	6		(2)	(6)	14
Noncontrolling Interest, Contributions from Noncontrolling Interest Holders	30						30
Proceeds from issuance of common stock	1
Other Preferred Stock Dividends and Adjustments	0
Gain on Redemption of Redeemable Preferred Stock	78			78
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(7)						(7)
Balance at Dec. 31, 2016	$ 4,446	$ 4	$ 8,358	$ (3,787)	$ (2,399)	$ (135)	$ 2,405

Nature of Business

Nature of Business	12 Months Ended
	Dec. 31, 2016
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 leading integrated power company built on the strength of the nation's largest and most diverse competitive electric generation portfolio and leading retail electricity platform. NRG aims to create a sustainable energy future by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. The Company owns and operates approximately 47,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG. Generation consists of the Company’s wholesale operations, commercial operations, EPC operations, energy services and other critical related functions. NRG has traditionally referred to this business as its wholesale power generation business. In addition to the traditional functions from NRG’s wholesale power generation business, Generation also includes NRG’s business solutions, which include demand response, commodity sales, energy efficiency and energy management services, and NRG’s conventional distributed generation business, consisting of reliability, combined heat and power, thermal and district heating and cooling and large-scale distributed generation. Retail is a consumer facing business that includes the Company’s residential retail and C&I business. Products and services range from retail energy, portable solar and battery products home services, and a variety of bundled products which combine energy with protection products, energy efficiency and renewable energy solutions as well as other distributed and reliability products. Renewables operates the Company’s existing renewables business, including operation of the NRG Yield renewable assets. Renewables is also one of the largest solar and wind power developers and owner-operators in the U.S., having developed, constructed and financed a full range of solutions for utilities, schools, municipalities and commercial market segments. GenOn Liquidity and Ability to Continue as a Going Concern As disclosed in Note 12, Debt and Capital Leases , $691 million of GenOn's Senior Notes excluding $8 million of associated premiums, are current within the GenOn consolidated balance sheet as of December 31, 2016 and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. Based on current projections, GenOn is not expected to have sufficient liquidity to repay the GenOn Senior Notes due in June 2017. As a result of these factors, there is substantial doubt about GenOn's ability to continue as a going concern. As a result of the substantial doubt about GenOn’s ability to continue as a going concern, along with additional factors, there is substantial doubt about certain of GenOn’s subsidiaries’ ability to continue as a going concern. As of December 31, 2016, GenOn has cash and cash equivalents of $1.0 billion , of which $471 million and $100 million is held by GenOn Mid-Atlantic and REMA, respectively. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period for four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. Additionally, GenOn Mid-Atlantic and REMA must be in compliance with the requirement to provide credit support to the owner lessors securing their obligations to pay scheduled rent under their respective leases. As a result, GenOn Mid-Atlantic has not been able to make distributions of cash and certain other restricted payments since the quarter ended March 31, 2014 which was the last quarterly period for which GenOn Mid-Atlantic satisfied the conditions under its operating agreement. REMA has not satisfied the conditions under its operating agreement to make distributions of cash and certain other restricted payments since 2009. NRG, GenOn's parent company, has no obligation to provide any financial support to GenOn other than under the secured intercompany revolving credit agreement between NRG and GenOn and NRG Americas. As of December 31, 2016, $228 million was available to be used by GenOn under the $500 million revolving credit agreement. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including the pension liabilities associated with GenOn employees. GenOn is currently considering all options available to it, including negotiations with creditors, refinancing the GenOn Senior Notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position. As of December 31, 2016, GenOn represents 15.6% of the Company's consolidated total assets, 16.9% of the Company's consolidated total liabilities and contributed $94 million to the Company's consolidated cash from operations in 2016. NRG Yield, Inc. Ownership In 2013, 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. In 2013 and 2014, NRG Yield, Inc. issued Class A common stock to its public shareholders and utilized the proceeds to acquire a controlling interest in NRG Yield LLC, through its ownership of Class A units. At that time, the Company owned the Class B common stock of NRG Yield, Inc. and the Class B units of NRG Yield LLC. On May 14, 2015, NRG Yield, Inc. completed a stock split in connection with which each outstanding share of Class A common stock was split into one share of Class A common stock and one share of Class C common stock, and each outstanding share of Class B common stock was split into one share of Class B common stock and one share of Class D common stock. A similar split was effected at NRG Yield LLC with respect to its member units. The Company consolidates NRG Yield, Inc. for financial reporting purposes as it maintains a controlling voting interest, and presents the public ownership of the Class A and Class C common stock as noncontrolling interest. The Company receives distributions from NRG Yield LLC, through its ownership of Class B and Class D units. The following table represents the structure of NRG Yield, Inc. as of December 31, 2016 :

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2016
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 GAAP. The ASC, established by the FASB, is the source of authoritative 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 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 The Company's businesses are segregated as follows: Generation (previously named Generation/Business), which includes generation, international and BETM (previously part of Corporate); Retail which includes Mass customers (previously Retail Mass), and Business Solutions, which includes C&I customers and other distributed and reliability products (previously in the Generation segment); Renewables (previously named NRG Renew), which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. The Company's corporate segment include residential solar (previously part of NRG Home) and electric vehicle services. During 2016, the Company began reporting the results of its residential solar business in its corporate segment and its international business in its Generation segment. The Company's segment structure and its allocation of corporate expenses were updated to reflect how management 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. 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. Of these funds, as of December 31, 2016, approximately $53 million is designated for current debt service payments, $51 million is designated to fund operating expenses, and $58 million is designated to fund distributions, with the remaining $284 million restricted for reserves including debt service, performance obligations and other reserves, as well as capital expenditures. 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. In addition, the Company considers a reserve for doubtful accounts based on the credit worthiness of the customers and continually reviews and adjusts for current economic trends that might impact the level of future credit losses. The reserve represents management's best estimate of uncollectible amounts. As of December 31, 2016 and 2015, the allowance for doubtful accounts was $30 million and $21 million , respectively. 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 weighted average cost. The Company removes these inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the fuel oil, coal, raw materials, and spare parts costs in the ordinary course of business. Finished goods inventory is valued at the lower of cost or net realizable value with cost being determined on a first-in first-out basis. The Company removes these inventories as they are sold to customers. 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 or, in the case of business acquisitions, fair value; however, impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. See Note 3 , Business Acquisitions and Dispositions , for more information on acquired property, plant and equipment. 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 indicated 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 consolidated 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 an other-than-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 Costs and Capitalized Interest Development costs 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 interest, and capitalized project development costs are reclassified to property, plant and equipment and depreciated 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. 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, 2016 , 2015 , and 2014 , was $43 million , $30 million , and $29 million , respectively. 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. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt. Intangible Assets Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, power purchase agreements, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, the Company 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. As of December 31, 2016 and 2015, the Company had accumulated amortization related to its intangible assets of $1.8 billion and $1.5 billion , respectively. 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, 2016 . 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. The Company first assesses 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. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. 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 the implied fair value, an impairment charge is recognized for the excess. For further discussion of goodwill and goodwill impairment losses recognized during 2016 and 2015, refer to Note 11 , Goodwill and Other Intangibles . Income Taxes The Company 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. The Company 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. The Company reports some of its 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. The Company measures its 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 its 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. The Company 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 the Company'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 — The Company records its bank of emission allowances as part of 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. The Company 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 $154 million , $165 million and $387 million for the years ended December 31, 2016 , 2015 , and 2014 , 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. The Company recorded receivables for unbilled revenues of $321 million , $309 million and $341 million as of December 31, 2016 , 2015 , and 2014 , respectively, for retail energy sales and services. Consumer product revenues are recognized when title and risk of loss pass to the retailer, distributor, or end-customer and when all of the following have occurred: a firm sales agreement is in place, delivery has occurred, pricing is fixed and determinable, and collection is reasonably assured. Revenue is recognized as the net amount expected to be received after deducting estimated amounts for product returns, discounts, and allowances based on historical return rates and reasonable judgment. Lessor Accounting Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. Many of these agreements are accounted for as operating leases under ASC 840 Leases. Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease. Contingent rental income recognized in the years ended December 31, 2016 , 2015 , and 2014 was $936 million , $777 million , and $544 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, 2016 , 2015 , and 2014 , the Company's revenues and cost of operations included gross receipts taxes of $102 million , $110 million , and $108 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 included in cost of operations and is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ( $90 million , $85 million and $86 million as of December 31, 2016 , 2015 , and 2014 , 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 The Company 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. The Company's primary derivative instruments are power purchase or 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, the Company 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 a 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. In this case, the gain or loss previously deferred in accumulated OCI would be frozen until the underlying hedged instrument is delivered unless the transactions being hedged are no longer probable of occurring in which case the amount in 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 consolidated 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 consolidated statements of operations. For the years ended December 31, 2016 , 2015 , and 2014 , amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2016 , 2015 , and 2014 were $(11) million , $(10) million and $1 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 payable, 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 The Company accounts for 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, the Company 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 The Company offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. The Company 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 the Company'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. The Company'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. The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Stock-Based Compensation The Company 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 market stock 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 the Company'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 The Company 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 the Company 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. For certain investments that relate to tax equity arrangements, equity earnings are allocated using the hypothetical liquidation at book value, or HLBV, method which is described below. Distributions from equity method investments that represent earnings on the Company's investment are included within cash flows from operating activities and distributions from equity method investments that represent a return of the Company's investment are included within cash flows from investing activities. Tax Equity Arrangements The Company’s redeemable noncontrolling interest in subsidiaries and noncontrolling interest, included in stockholders' equity, represents third-party interests in the net assets under certain tax equity arrangements, which are consolidated by the Company, that have been entered into to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits. The Company has determined that the provisions in the contractual agreements of these structures represent substantive profit sharing arrangements. Further, the Company has determ

Business Acquisitions and Dispo

Business Acquisitions and Dispositions (Notes)	12 Months Ended
	Dec. 31, 2016
Business Acquisitions and Dispositions [Abstract]
Business Acquisitions and Dispositions	Business Acquisitions and Dispositions The Company has completed the following business acquisitions and dispositions that are material to the Company's financial statements: Acquisitions 2016 Utility-Scale Solar and Wind Acquisition On November 2, 2016, the Company acquired equity interests in a tax equity portfolio from SunEdison, located in Utah, comprised of 530 MW of mechanically-complete solar assets, of which NRG’s net interest based on cash to be distributed is 265 MW, for upfront cash consideration of $111 million . In connection with the acquisition, the Company assumed non-recourse debt of $222 million . The Company also borrowed additional amounts of $65 million during the fourth quarter of 2016, as described in Note 12 , Debt and Capital Leases , which effectively reduced the Company's use of liquidity related to the acquisition. The Company does not have a controlling interest in the tax equity portfolio and, accordingly, its interest is recorded as an equity method investment. The purchase price was preliminarily allocated to the equity method investment balance of approximately $328 million , current assets of $5 million and the assumed non-recourse debt of $222 million . The assets reached commercial operations during the fourth quarter of 2016 and have 20-year PPAs with PacificCorp. The Company acquired a 110 MW portfolio of construction-ready and 71 MW of development solar assets in Hawaii from SunEdison for upfront cash consideration of $2 million on October 3, 2016 and a 154 MW construction-ready solar project in Texas for upfront cash consideration of $11 million on November 9, 2016. In addition to the total $124 million in upfront cash consideration paid for the above acquisitions, the Company expects to make an estimated $59 million in additional payments contingent upon future development milestones. 2016 Solar Distributed Generation Acquisition On October 3, 2016, the Company acquired a 29 MW portfolio of mechanically-complete and construction-ready distributed generation solar assets from SunEdison for cash consideration of approximately $67 million excluding post-closing adjustments which reduced the purchase price by $5 million . Subsequent to the acquisition, the Company sold the majority of these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc., and expects to sell the remaining assets into a similar portfolio in 2017. The purchase price was preliminarily allocated to $47 million in construction in progress and $15 million in intangible assets. 2015 Acquisition of Desert Sunlight On June 29, 2015, NRG Yield, Inc., through its subsidiary NRG Yield Operating LLC, acquired 25% of the membership interest in Desert Sunlight Investment Holdings, LLC, which owns two solar photovoltaic facilities that total 550 MW located in Desert Center, California from EFS Desert Sun, LLC, an affiliate of GE Energy Financial Services, for a purchase price of $285 million . The Company accounts for its 25% investment as an equity method investment. 2014 Acquisition of Alta Wind On August 12, 2014, NRG Yield, Inc., through its subsidiary NRG Yield Operating LLC, or Yield Operating, completed the acquisition of 100% of the membership interests of Alta Wind Asset Management Holdings, LLC, Alta Wind Company, LLC, Alta Wind X Holding Company, LLC, and Alta Wind XI Holding Company, LLC, which collectively own seven wind facilities that total 947 MW located in Tehachapi, California and a portfolio of land leases, or the Alta Wind Assets. Power generated by the Alta Wind facility is sold to Southern California Edison under long-term power purchase agreements with 21 years of remaining contract life for Alta I-V. The Alta X and XI power purchase agreements began in January 2016 with terms of 22 years and sold energy and renewable energy credits on a merchant basis during the years ended December 31, 2015 and 2014. The purchase price of the Alta Wind Assets was $923 million , which was comprised of a purchase price of $870 million and $53 million paid for working capital balances. In order to fund the purchase price of the acquisition, NRG Yield, Inc. issued 12,075,000 shares of its Class A common stock on July 29, 2014 for net proceeds of $630 million . In addition, on August 5, 2014, Yield Operating issued $500 million in aggregate principal amount at par of 5.375% senior notes due August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year, and commenced on February 15, 2015. The notes are senior unsecured obligations of Yield Operating and are guaranteed by NRG Yield LLC, Yield Operating’s parent company, and by certain of Yield Operating’s wholly owned subsidiaries. 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 business combination was completed as of August 11, 2015, at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 31, 2014, as well as adjustments made through August 11, 2015, when the allocation became final. The purchase price of $923 million was allocated as follows: Acquisition Date Fair Value at December 31, 2014 Measurement period adjustments Revised Acquisition Date (In millions) Assets Cash $ 22 — $ 22 Current and non-current assets 49 (2 ) 47 Property, plant and equipment 1,304 6 1,310 Intangible assets 1,177 (6 ) 1,171 Total assets acquired 2,552 (2 ) 2,550 Liabilities Debt 1,591 — 1,591 Current and non-current liabilities 38 (2 ) 36 Total liabilities assumed 1,629 (2 ) 1,627 Net assets acquired $ 923 $ — $ 923 2014 Acquisition of Dominion's Competitive Electric Retail Business On March 31, 2014, the Company acquired the competitive retail electricity business of Dominion Resources, Inc., or Dominion. The acquisition of Dominion's competitive retail electricity business increased NRG’s retail portfolio by approximately 540,000 customers in the aggregate by the end of 2014. The acquisition supports NRG's ongoing efforts to expand the Company's retail footprint in the Northeast and to grow its retail position in Texas. The Company paid approximately $192 million as cash consideration for the acquisition, including $165 million of purchase price and $27 million paid for working capital balances, which was funded by cash on hand. The purchase price was allocated to the following: $40 million to accounts receivable-trade, $64 million to customer relationships, $9 million to trade names, $14 million to current assets, $21 million to derivative assets, $47 million to current and non-current liabilities, and goodwill of $91 million of which $8 million is deductible for U.S. income tax purposes in future periods. The consideration and assets include amounts paid for customer relationships in the Northeast that were accounted for as an asset acquisition. The factors that resulted in goodwill arising from the acquisition include the revenues associated with new customers in new regions and through the synergies associated with combining a new retail business with the Company's existing retail and generation assets. The accounting for the Dominion acquisition was completed as of March 30, 2015, at which point the provisional fair values became final with no material changes. 2014 Acquisition of EME On April 1, 2014, the Company acquired substantially all of the assets of EME. EME, through its subsidiaries and affiliates, owned or leased and operated a portfolio of approximately 8,000 MW consisting of wind energy facilities and coal- and gas-fired generating facilities. The Company paid an aggregate purchase price of $3.5 billion , which was funded through the issuance of 12,671,977 shares of NRG common stock on April 1, 2014, the issuance of $700 million in newly-issued corporate debt, as described in Note 12 , Debt and Capital Leases , and cash on hand. The Company also assumed non-recourse debt of approximately $1.2 billion . In connection with the transaction, NRG agreed to certain conditions with the parties to the Powerton and Joliet, or POJO, sale-leaseback transaction subject to which an NRG subsidiary assumed the POJO leveraged leases and NRG guaranteed the remaining payments under each lease, which total $405 million through 2034. On April 30, 2014, subsequent to the acquisition, the Company acquired the remaining 50% ownership of Mission Del Sol LLC, which owns the Sunrise facility, a 586 MW natural gas facility in Fellows, California, from Chevron Power Holdings Inc. increasing the Company's ownership interest to 100% in exchange for the Company's 50% interest in six cogeneration facilities, previously co-owned with Chevron Power Holdings Inc. 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 EME acquisition was completed as of March 31, 2015, at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 31, 2014, as well as adjustments made through March 31, 2015, when the allocation became final. Measurement period adjustments primarily reflect the tax impact of the acquisition date fair values and final estimates for asset retirement obligations. The purchase price of $3.5 billion was allocated as follows: Acquisition Date Fair Value at December 31, 2014 Measurement period adjustments Revised Acquisition Date (In millions) Assets Cash $ 1,422 $ — $ 1,422 Current assets 724 72 796 Property, plant and equipment 2,438 (3 ) 2,435 Intangible assets 172 — 172 Goodwill 334 (56 ) 278 Non-current assets 773 — 773 Total assets acquired 5,863 13 5,876 Liabilities Current and non-current liabilities 629 13 642 Out-of-market contracts and leases 159 — 159 Long-term debt 1,249 — 1,249 Total liabilities assumed 2,037 13 2,050 Less: noncontrolling interest 352 — 352 Net assets acquired $ 3,474 $ — $ 3,474 Dispositions 2016 Potrero Disposition On September 26, 2016, NRG Potrero LLC, or Potrero, an indirect wholly owned subsidiary of GenOn Americas Generation, completed the sale of real property at the Potrero generating station located in San Francisco, CA to California Barrel Company, LLC for total consideration of $86 million , consisting of $74 million of cash received, which is net of $8 million of closing costs and $4 million to be held in escrow in order to cover post-closing obligations. This transaction resulted in a gain on sale of $74 million . 2016 Disposition of Majority Interest in EVgo On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for total consideration of approximately $39 million , including $17 million in cash received, which is net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge Partners, all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG retained its original financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California. NRG has contracted with EVgo to continue to build the remaining required Freedom Stations and commercial and multi-family parking spaces for electric vehicle charging required under this obligation and EVgo will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $78 million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual of NRG's remaining obligation under its agreement with the CPUC of $56 million , of which $47 million remains as of December 31, 2016. At December 31, 2016, the Company's remaining 35% interest in EVgo of $5 million was accounted for as an equity method investment. 2016 Rockford Disposition On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million , subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Rockford is a 450 MW natural gas facility located in Rockford, Illinois. The transaction triggered an indicator of impairment as the sales price was less than the carrying amount of the assets and as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sales price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016 to reduce the carrying amount of the assets held for sale to the fair market value. On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million , including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to Note 10 , Asset Impairments . 2016 Aurora Disposition On May 12, 2016, GenOn entered into an agreement with RA Generation, LLC to sell the Aurora Generating Station, or Aurora, for cash consideration of $365 million , subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Aurora is an 878 MW natural gas facility located in Aurora, Illinois. On July 12, 2016, GenOn completed the sale of Aurora for cash proceeds of $369 million , including $4 million in adjustments for the PJM base residual auction results and estimated working capital, which is subject to further adjustment. The Company recorded a gain of approximately $188 million recognized within the Company's consolidated results of operations during the quarter ended September 30, 2016. 2016 Seward Disposition On November 24, 2015, GenOn entered into an agreement with Seward Generation, LLC and an affiliate of Robindale Energy Services, Inc. to sell the Seward Generating Station, a 525 MW coal-fired facility in Pennsylvania, for cash consideration of $75 million . At December 31, 2015, GenOn had classified on its balance sheet the assets and liabilities of Seward as held for sale. On February 2, 2016, GenOn completed the sale of Seward and received gross cash proceeds of $75 million , excluding $3 million cash on hand transferred to the buyer. GenOn will also receive $5 million in deferred cash consideration in five $1 million annual installments and up to $2.5 million in payments contingent upon certain environmental requirements being imposed by August 2017. In addition, Robindale committed to future inventory purchases from GenOn of $13 million through 2019. 2016 Shelby Disposition On November 9, 2015, GenOn entered into an agreement with an affiliate of Rockland Power Partners II, LP to sell the Shelby Generating Station, a 352 MW natural gas-fired facility located in Illinois for cash consideration of $46 million . At December 31, 2015, GenOn had classified on its balance sheet the assets and liabilities of Shelby as held for sale. On March 1, 2016, GenOn completed the sale of Shelby for cash proceeds of $46 million , which resulted in a gain of $29 million recognized during the first quarter of 2016. In addition, GenOn retained $10 million related to future revenue rights retained as part of the agreement of which $8 million had been received as of December 31, 2016. 2015 Disposition of Altenex On December 31, 2015, the Company completed the sale of its 32% interest in Altenex, LLC to Edison Energy, LLC and Edison Energy NewCo 2, LLC for cash consideration of $26 million . The Company had accounted for its investment in Altenex as an equity method investment and recognized a loss of $14 million as a result of the transactions within the Company's consolidated statements of operations. 2014 Sale of Sabine On December 2, 2014, the Company, through its subsidiaries GenOn Sabine (Delaware), Inc. and GenOn Sabine (Texas), Inc., completed the sale of its 50% interest in Sabine Cogen, L.P., or Sabine, to Bayou Power, LLC, an affiliate of Rockland Capital, LLC. Sabine owns a 105 MW natural gas-fired cogeneration facility located in Texas. The Company received cash consideration of $35 million at closing. A gain of $18 million was recognized as a result of the transaction and recorded as a gain on sale of equity method investments within the Company's consolidated statements of operations. 2014 Disposition of 50% Interest in Petra Nova Parish Holdings LLC On July 3, 2014, the Company, through its wholly owned subsidiary Petra Nova Holdings LLC, sold 50% of its interest in Petra Nova Parish Holdings LLC to JX Nippon Oil Exploration (EOR) Limited, or JX Nippon, a wholly owned subsidiary of JX Nippon Oil & Gas Exploration Corporation. As a result of the sale, the Company no longer has a controlling interest in and has deconsolidated Petra Nova Parish Holdings LLC as of the date of the sale. On July 7, 2014, the Company made its initial capital contribution into the partnership of $35 million , which was funded with a portion of the sale proceeds of $76 million . On March 3, 2014, Petra Nova CCS I LLC, a wholly owned subsidiary of Petra Nova Parish Holdings LLC, entered into a fixed-price agreement to build and operate a CCF at the W.A. Parish facility with a consortium of Mitsubishi Heavy Industries America, Inc. and TIC - The Industrial Company. Notice to proceed for the construction on the CCF was issued on July 15, 2014, and commercial operation began in late 2016. Petra Nova Parish Holdings LLC also owns a 75 MW peaking unit at W.A. Parish, which achieved commercial operations on June 26, 2013. The peaking unit will be converted into a cogeneration facility to provide power and steam to the CCF. The CCF is being financed by: (i) up to $167 million from a U.S. DOE CCPI grant of which $7 million has already been received from the grant in the initial design and engineering phase and $106 million has already been received from the grant under the construction phase, (ii) $250 million in loans provided by the Japan Bank for International Cooperation and Mizuho Bank, Ltd., and (iii) approximately $300 million in equity contributions from each of the Company and JX Nippon. The Company’s contribution will include investments already made during the development of the project. In February 2016, Petra Nova Parish Holdings LLC received notice of an additional $23 million in U.S. DOE funding. On July 14, 2014, Petra Nova Parish Holdings LLC entered into two credit facilities, or the Petra Nova Parish Credit Agreements, to fund the cost of construction of the CCF at the W.A. Parish facility. The Petra Nova Parish Credit Agreements are comprised of a $75 million Nippon Export and Investment Insurance, or NEXI, covered loan and a $175 million Japan Bank for International Cooperation, or JBIC, facility. The NEXI covered loan has an interest rate of LIBOR plus an applicable margin of 1.75% and the JBIC facility has an interest rate of LIBOR plus an applicable margin of 0.50% during the construction phase which escalates to an applicable margin of 1.50% upon completion of the CCF. Both credit facilities mature in April 2026. NRG has guaranteed its 50% share of the obligations under the Petra Nova Parish Credit Agreements through mechanical completion as defined by the credit agreements. Transfer of Assets under Common Control On September 1, 2016, the Company completed the sale of its remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total cash consideration of $78.5 million , plus an immaterial working capital adjustment. In addition, NRG Yield, Inc. assumed non-recourse project level debt of $496 million . On November 3, 2015, the Company sold 75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities totaling 814 net MW, to NRG Yield, Inc. NRG Yield, Inc. paid total cash consideration of $209 million , subject to working capital adjustments. NRG Yield, Inc. is responsible for its pro-rata share of non-recourse project debt of $193 million and noncontrolling interest associated with a tax equity structure of $159 million (as of the acquisition date). In February 2016, the Company made a final working capital payment of $2 million to NRG Yield, Inc. reducing total cash consideration to $207 million . On January 2, 2015, the Company sold the following facilities to NRG Yield, Inc.: Walnut Creek, the Tapestry projects (Buffalo Bear, Pinnacle and Taloga) and Laredo Ridge. NRG Yield, Inc. paid total cash consideration of $489 million , including $9 million of working capital adjustments, plus assumed project level debt of $737 million . On June 30, 2014, the Company sold the following facilities to NRG Yield, Inc.: High Desert, Kansas South, and El Segundo Energy Center. NRG Yield, Inc. paid total cash consideration of $357 million , which represents a base purchase price of $349 million and $8 million of working capital adjustments, plus assumed project level debt of approximately $612 million . The above sales were recorded as transfers of entities under common control and the related assets were transferred at their carrying value.

Fair Value of Financial Instrum

Fair Value of Financial Instruments (Notes)	12 Months Ended
	Dec. 31, 2016
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 posted 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 the Company's recorded financial instruments not carried at fair market value are as follows: As of December 31, 2016 2015 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Assets Notes receivable (a) $ 34 $ 34 $ 73 $ 73 Liabilities Long-term debt, including current portion (b) $ 19,406 $ 18,566 $ 19,620 $ 18,263 (a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets. (b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt 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. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of December 31, 2016 and 2015: As of December 31, 2016 As of December 31, 2015 Level 2 Level 3 Level 2 Level 3 (In millions) Long-term debt, including current portion $ 11,055 $ 7,511 $ 11,028 $ 7,235 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, 2016 Fair Value Level 1 Level 2 Level 3 Total (In millions) Investments in securities (classified within other non-current assets): Debt securities $ — $ — $ 17 $ 17 Available-for-sale securities 10 — — 10 Other (a) 10 — — 10 Nuclear trust fund investments: Cash and cash equivalents 25 — — 25 U.S. government and federal agency obligations 72 1 — 73 Federal agency mortgage-backed securities — 62 — 62 Commercial mortgage-backed securities — 17 — 17 Corporate debt securities — 84 — 84 Equity securities 292 — 54 346 Foreign government fixed income securities — 3 — 3 Other trust fund investments: U.S. government and federal agency obligations 1 — — 1 Derivative assets: Commodity contracts 559 551 92 1,202 Interest rate contracts — 49 — 49 Total assets $ 969 $ 767 $ 163 $ 1,899 Derivative liabilities: Commodity contracts $ 494 $ 635 $ 161 $ 1,290 Interest rate contracts — 88 — 88 Total liabilities $ 494 $ 723 $ 161 $ 1,378 (a) Consists primarily of mutual funds held in a rabbi trust for non-qualified deferred compensation plans for certain key and highly compensated employees and a total return swap that does not meet the definition of a derivative. As of December 31, 2015 Fair Value Level 1 Level 2 Level 3 Total (In millions) Investments in securities (classified within other non-current assets): Debt securities $ — $ — $ 17 $ 17 Available-for-sale securities 9 — — 9 Other (a) 14 — — 14 Nuclear trust fund investments: Cash and cash equivalents 6 — — 6 U.S. government and federal agency obligations 54 1 — 55 Federal agency mortgage-backed securities — 59 — 59 Commercial mortgage-backed securities — 25 — 25 Corporate debt securities — 81 — 81 Equity securities 280 — 54 334 Foreign government fixed income securities — 1 — 1 Other trust fund investments: U.S. government and federal agency obligations 1 — — 1 Derivative assets: Commodity contracts 622 1,449 149 2,220 Total assets $ 986 $ 1,616 $ 220 $ 2,822 Derivative liabilities: Commodity contracts $ 868 $ 1,036 $ 182 $ 2,086 Interest rate contracts — 128 — 128 Total liabilities $ 868 $ 1,164 $ 182 $ 2,214 (a) Primarily consists of mutual funds held in a rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative. There have been no transfers during the year ended December 31, 2016 between Levels 1 and 2. The following tables reconcile, for the years ended December 31, 2016 and 2015 , 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, 2016 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) Debt Securities Trust Fund Investments Derivatives (a) Total (In millions) Beginning balance as of January 1, 2016 $ 17 $ 54 $ (33 ) $ 38 Total gains/(losses) realized/unrealized: Included in earnings — — 12 12 Included in nuclear decommissioning obligations — (1 ) — (1 ) Purchases — 1 (29 ) (28 ) Transfers into Level 3 (b) — — (18 ) (18 ) Transfers out of Level 3 (b) — — (1 ) (1 ) Ending balance as of December 31, 2016 $ 17 $ 54 $ (69 ) $ 2 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, 2016 $ — $ — $ (14 ) $ (14 ) (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, 2015 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) Debt Securities Other Trust Fund Investments Derivatives (a) Total (In millions) Beginning balance as of January 1, 2015 $ 18 $ 11 $ 52 $ 80 $ 161 Total losses realized/unrealized: Included in earnings (1 ) (11 ) — (100 ) (112 ) Included in nuclear decommissioning obligations — — (2 ) — (2 ) Purchases — — 4 (19 ) (15 ) Transfers into Level 3 (b) — — — 3 3 Transfer out of Level 3 (b) — — — 3 3 Ending balance as of December 31, 2015 $ 17 $ — $ 54 $ (33 ) $ 38 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, 2015 $ — $ — $ — $ (30 ) $ (30 ) (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 the Company'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 7% of derivative assets and 12% 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 for interest rate swaps is calculated utilizing the bilateral method based on published default probabilities. For commodities, 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. For interest rate swaps and commodities, 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, 2016 , the credit reserve resulted in an $11 million decrease in fair value in operating revenue and cost of operations. As of December 31, 2015 the credit reserve resulted in a $5 million increase in fair value which is composed of a $2 million gain in OCI and a $3 million gain 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, 2016 , 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. NRG's significant positions classified as Level 3 include physical and financial power and physical coal executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power and coal location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value. The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of December 31, 2016 and 2015: Significant Unobservable Inputs December 31, 2016 Fair Value Input/Range Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average (In millions) Power Contracts $ 40 $ 107 Discounted Cash Flow Forward Market Price (per MWh) $ 11 $ 104 $ 31 Coal Contracts — 1 Discounted Cash Flow Forward Market Price (per ton) 42 51 45 FTRs 52 53 Discounted Cash Flow Auction Prices (per MWh) (22 ) 17 — $ 92 $ 161 Significant Unobservable Inputs December 31, 2015 Fair Value Input/Range Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average (In millions) Power Contracts $ 86 $ 100 Discounted Cash Flow Forward Market Price (per MWh) $ 10 $ 92 $ 27 Coal Contracts — 12 Discounted Cash Flow Forward Market Price (per ton) 28 45 35 FTRs 63 70 Discounted Cash Flow Auction Prices (per MWh) (98 ) 87 — $ 149 $ 182 The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2016 and 2015: Significant Unobservable Input Position Change In Input Impact on Fair Value Measurement Forward Market Price Power/Coal Buy Increase/(Decrease) Higher/(Lower) Forward Market Price Power/Coal Sell Increase/(Decrease) Lower/(Higher) FTR Prices Buy Increase/(Decrease) Higher/(Lower) FTR Prices Sell Increase/(Decrease) Lower/(Higher) Under the guidance of ASC 815, entities may choose to offset cash collateral posted 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, 2016 , the Company recorded $203 million of cash collateral posted and $2 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 the Company to cover the credit risk of the counterparty until positions settle. Counterparty Credit Risk As of December 31, 2016 , counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $231 million and NRG held collateral (cash and letters of credit) against those positions of $2 million , resulting in a net exposure of $229 million . Approximately 95% of the Company's exposure before collateral is expected to roll off by the end of 2018 . 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) (b) (% of Total) Utilities, energy merchants, marketers and other 100 Total 100 % Category Net Exposure (a) (b) (% of Total) Investment grade 67 % Non-Investment grade/Non-Rated 33 Total 100 % (a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices. (b) The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts. 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 $80 million as of December 31, 2016. 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. RTOs and ISOs The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and includes credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of overall market and are excluded from the above exposures. Exchange Traded Transactions The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk. Long Term Contracts Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, wind and solar PPAs. 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, 2016 , aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.1 billion , including $2.6 billion 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. Retail Customer Credit Risk The Company 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 in losses 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. The Company 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, 2016 , the Company's retail customer credit exposure to C&I and Mass customers was diversified across many customers and various industries, as well as government entities. The Company is also subject to risk with respect to its residential solar customers. The Company's bad debt expense was $48 million , $64 million , and $64 million for the years ending December 31, 2016 , 2015 , and 2014 , 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 Instr

Accounting for Derivative Instruments and Hedging Activities (Notes)	12 Months Ended
	Dec. 31, 2016
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 the Company 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. The Company 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 equity contracts. As the Company engages principally in the trading and marketing of its generation assets and retail businesses, 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 units' 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 NRG's retail businesses, 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 counterparties 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; and • Weather and hurricane derivative products used to mitigate a portion of retail'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 the Company's power plants; and • 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, 2016 , 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 2031; • Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2018; and • Other energy derivatives instruments extending through 2024. Also, as of December 31, 2016 , 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 2039; • Coal purchase contracts through 2021; • Power transmission contracts through 2025; • Natural gas transportation contracts and storage agreements through 2030; and • Coal transportation contracts through 2029. Interest Rate Swaps NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of December 31, 2016 , NRG had interest rate derivative instruments on recourse debt extending through 2021 and non-recourse debt extending through 2036, 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, 2016 and 2015 . 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, 2016 December 31, 2015 (In millions) Emissions Short Ton — 1 Coal Short Ton 41 35 Natural Gas MMBtu 85 293 Oil Barrel 1 1 Power MWh (28 ) (74 ) Capacity MW/Day (1 ) (1 ) Interest Dollars $ 3,429 $ 2,326 Equity Shares 1 1 The decrease in the natural gas position was primarily the result of the settlement of generation hedge positions and retail hedge positions. The increase in the interest rate position was primarily the result of entering into new interest rate swaps to hedge the Term Loan Facility, as described in Note 12 , Debt and Capital Leases . 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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Derivatives Designated as Cash Flow or Fair Value Hedges : Interest rate contracts current $ — $ — $ 28 $ 42 Interest rate contracts long-term 12 — 41 68 Total Derivatives Designated as Cash Flow or Fair Value Hedges 12 — 69 110 Derivatives Not Designated as Cash Flow or Fair Value Hedges : Interest rate contracts current — — 7 5 Interest rate contracts long-term 37 — 12 13 Commodity contracts current 1,062 1,915 1,049 1,674 Commodity contracts long-term 140 305 241 412 Total Derivatives Not Designated as Cash Flow or Fair Value Hedges 1,239 2,220 1,309 2,104 Total Derivatives $ 1,251 $ 2,220 $ 1,378 $ 2,214 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, 2016 (In millions) Commodity contracts: Derivative assets $ 1,202 $ (1,005 ) $ (1 ) $ 196 Derivative liabilities (1,290 ) 1,005 14 (271 ) Total commodity contracts (88 ) — 13 (75 ) Interest rate contracts: Derivative assets 49 (4 ) — 45 Derivative liabilities (88 ) 4 — (84 ) Total interest rate contracts (39 ) — — (39 ) Total derivative instruments $ (127 ) $ — $ 13 $ (114 ) 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, 2015 (In millions) Commodity contracts: Derivative assets $ 2,220 $ (1,616 ) $ (113 ) $ 491 Derivative liabilities (2,086 ) 1,616 271 (199 ) Total commodity contracts 134 — 158 292 Interest rate contracts: Derivative liabilities (128 ) — — (128 ) Total derivative instruments $ 6 $ — $ 158 $ 164 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, 2016 Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2015 $ (101 ) $ (101 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts 21 21 Mark-to-market of cash flow hedge accounting contracts 14 14 Accumulated OCI balance at December 31, 2016, net of $16 tax $ (66 ) $ (66 ) Losses expected to be realized from other comprehensive loss during the next 12 months, net of $4 tax $ (16 ) $ (16 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2016 . Year Ended December 31, 2015 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2014 $ (1 ) $ (67 ) $ (68 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts 1 14 15 Mark-to-market of cash flow hedge accounting contracts — (48 ) (48 ) Accumulated OCI balance at December 31, 2015, net of $16 tax $ — $ (101 ) $ (101 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2015 . Year Ended December 31, 2014 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2013 $ (1 ) $ (22 ) $ (23 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts — 13 13 Mark-to-market of cash flow hedge accounting contracts — (58 ) (58 ) Accumulated OCI balance at December 31, 2014, net of $35 tax $ (1 ) $ (67 ) $ (68 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2014 . 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 December 31, 2016, the Company's regression analysis for Viento Funding II interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result, the Company de-designated the Viento Funding II cash flow hedges as of December 31, 2016, and will prospectively mark 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 the Company'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, 2016 2015 2014 (In millions) Unrealized mark-to-market results Reversal of previously recognized unrealized gains on settled positions related to economic hedges $ (245 ) $ (275 ) $ (15 ) Reversal of acquired gain positions related to economic hedges (60 ) (106 ) (333 ) Net unrealized gains on open positions related to economic hedges 20 9 361 Total unrealized mark-to-market (losses)/gains for economic hedging activities (285 ) (372 ) 13 Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity 10 (46 ) 1 Reversal of acquired gain positions related to trading activity — (14 ) (32 ) Net unrealized gains/(losses) on open positions related to trading activity 18 (16 ) 45 Total unrealized mark-to-market gains/(losses) for trading activity 28 (76 ) 14 Total unrealized (losses)/gains $ (257 ) $ (448 ) $ 27 Year Ended December 31, 2016 2015 2014 (In millions) Unrealized (losses)/gains included in operating revenues $ (837 ) $ (320 ) $ 515 Unrealized gains/(losses) included in cost of operations 580 (128 ) (488 ) Total impact to statement of operations — energy commodities $ (257 ) $ (448 ) $ 27 Total impact to statement of operations — interest rate contracts $ 36 $ 17 $ (31 ) The reversal of gain or loss positions acquired as part of 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, 2016 , the $20 million gain from economic hedge positions was primarily the result of an increase in the value of forward purchases of natural gas due to an increase in natural gas prices. During 2016, the Company closed out and financially settled certain open positions with counterparties. The closure and financial settlements with these counterparties were necessary to manage the increase in collateral posting requirements following rating agency downgrades for GenOn and to reduce expected collateral costs associated with exchange cleared hedge transactions. GenOn realized approximately $38 million due to the closure and financial settlement of all open positions with one of GenOn's counterparties during the second quarter of 2016, for which $18 million , $19 million and $1 million would have been realized during the remainder of 2016, 2017 and 2018, respectively. During the third quarter of 2016, GenOn realized $98 million due to the closure and financial settlement of certain positions with an additional counterparty for which $82 million , $13 million and $3 million would have otherwise been realized in 2017, 2018, and 2019, respectively. GenOn has entered into additional transactions with NRG Power Marketing LLC and an external counterparty in order to re-hedge the positions settled with certain counterparties. For the year ended December 31, 2015 , the $9 million gain from economic hedge positions was primarily the result of an increase in the value of forward sales of electricity due to a decrease in power prices. For the year ended December 31, 2014 , the $361 million gain from economic hedge positions was primarily the result of an increase in the value of forward sales of natural gas due to a decrease in natural gas prices. During 2014, NRG had interest rate swaps designated as cash flow hedges on the Dandan solar project. The notional amount on the swaps exceeded the actual debt draws on the project. As such, the Company discontinued cash flow hedge accounting for these contracts and $6 million of losses previously deferred in OCI was recognized in the statement of operations for the year ended December 31, 2014 . 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, 2016 was $36 million . The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2016 was $56 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, which was approximately $14 million as of December 31, 2016 . See Note 4 , Fair Value of Financial Instruments , for discussion regarding concentration of credit risk.

Nuclear Decommissioning Trust F

Nuclear Decommissioning Trust Fund (Notes)	12 Months Ended
	Dec. 31, 2016
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, 2016 As of December 31, 2015 (In millions, except otherwise noted) Fair Value Unrealized Gains Unrealized Losses Weighted- average maturities (in years) Fair Value Unrealized Gains Unrealized Losses Weighted- average maturities (in years) Cash and cash equivalents $ 25 $ — $ — — $ 6 $ — $ — — U.S. government and federal agency obligations 73 1 — 11 55 1 — 11 Federal agency mortgage-backed securities 62 1 1 25 59 1 — 25 Commercial mortgage-backed securities 17 — 1 26 25 — 2 28 Corporate debt securities 84 1 2 11 81 1 1 10 Equity securities 346 214 — — 334 199 — — Foreign government fixed income securities 3 — — 9 1 — — 9 Total $ 610 $ 217 $ 4 $ 561 $ 202 $ 3 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 using the specific identification method. Year Ended December 31, 2016 2015 2014 (In millions) Realized gains $ 26 $ 21 $ 29 Realized losses 11 14 8 Proceeds from sale of securities 510 631 600

Inventory (Notes)

Inventory (Notes)	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Inventory	Inventory Inventory consisted of: As of December 31, 2016 2015 (In millions) Fuel oil $ 289 $ 312 Coal/Lignite 334 471 Natural gas 28 12 Spare parts 413 437 Other 47 20 Total Inventory $ 1,111 $ 1,252 During the year ended December 31, 2015, the Company recorded a lower of weighted average cost or market adjustment related to fuel oil of $19 million .

Notes Receivable (Notes)

Notes Receivable (Notes)	12 Months Ended
	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Capital Leases and Notes Receivable	Notes Receivable Notes receivable consist of fixed and variable rate notes related primarily to amounts owed to the Company from transmission owners for certain projects for the financing of network upgrades. The Company's notes receivable were as follows: As of December 31, 2016 2015 (In millions) Notes receivable $ 34 $ 73 Less current maturities (a) 17 20 Total notes receivable — non-current $ 17 $ 53 (a) The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment The Company's major classes of property, plant, and equipment were as follows: As of December 31, Depreciable 2016 2015 Lives (In millions) Facilities and equipment $ 21,445 $ 21,633 1-40 Years Land and improvements 1,026 1,226 Nuclear fuel 601 545 5 Years Office furnishings and equipment 457 462 2-10 Years Construction in progress 697 627 Total property, plant, and equipment 24,226 24,493 Accumulated depreciation (6,314 ) (5,761 ) Net property, plant, and equipment $ 17,912 $ 18,732 The Company decreased accumulated depreciation and facilities and equipment within total property, plant and equipment by approximately $1 billion , respectively, to adjust amounts previously presented as of December 31, 2015. This adjustment had no impact on net assets at December 31, 2015. Accordingly, the Company does not consider the adjustment to be material to the consolidated balance sheet. Consolidated operating income and net income for the year ended December 31, 2016 were not impacted by the adjustment. The Company recorded long-lived asset impairments during the years ended December 31, 2016 and 2015 , as further described in Note 10 , Asset Impairments .

Asset Impairments (Notes)

Asset Impairments (Notes)	12 Months Ended
	Dec. 31, 2016
Asset Impairment Charges [Abstract]
Asset Impairments	Asset Impairments 2016 Impairment Losses Rockford — As described in Note 3 , Business Acquisitions and Dispositions , on May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford generating stations for cash consideration of $55 million . The transaction triggered an indicator of impairment as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $17 million during the year ended December 31, 2016, to reduce the carrying amount of the assets held for sale to the fair market value. Mandalay and Ormond Beach — On May 26 , 2016, the CPUC rejected a multi-year resource adequacy contract between Mandalay and SCE. Also during the second quarter of 2016, the Statewide Advisory Committee on Cooling Water Intake Structures, or SACCWIS, issued a draft April 2016 Report noting that CAISO plans to continue to assume in its transmission studies that Ormond Beach will not operate after December 31, 2020, the deadline for Ormond Beach compliance with California regulations to mitigate once-through cooling (OTC) impacts. The Company does not anticipate that contracts of sufficient value can be secured to support the significant investment required to design, permit, construct and operate measures required for OTC compliance. As a result, on May 6, 2016, the Company notified SACCWIS that it does not expect to continue to operate Ormond Beach beyond 2020. Additionally, during the second quarter of 2016, CAISO issued its Local Capacity Requirements report for 2017 indicating unfavorable changes within the local reliability areas in which both Mandalay and Ormond Beach are located. The culmination of these events were considered to be indicators of impairment and as a result, the Company performed impairment tests for the Mandalay and Ormond Beach assets. Based on the results of the impairment tests, the Company determined that the carrying amount of these assets was higher than the estimated future net cash flows expected to be generated by the respective assets and that the Mandalay and Ormond Beach assets were impaired. The fair value of the Mandalay and Ormond Beach operating units was determined using the income approach which utilizes estimates of discounted future cash flows, which were Level 3 fair value measurements and include key inputs such as forecasted contract prices, forecasted operating expenses and discount rates. The Company measured the impairment losses as the difference between the carrying amount of the Mandalay and Ormond Beach operating units and the present value of the estimated future net cash flows for each respective operating unit. The Company recorded an impairment loss of $16 million and $43 million for Mandalay and Ormond Beach, respectively, during the second quarter of 2016. In addition, during the fourth quarter of 2016 the declining prices for resource adequacy contracts available in the reliability sub-area which Ormond Beach operates in further reduced anticipated cash flows to be generated from Ormond Beach through its anticipated retirement in 2020. This was considered to be an indicator of impairment and as a result, the Company performed an impairment test for the Ormond Beach assets. The Company determined that the carrying amount of these assets was higher than the estimated future net cash flows expected to be generated by the assets and that the Ormond Beach assets were impaired. The fair value of the Ormond Beach operating unit was determined using the income approach which utilizes estimates of discounted future cash flows, which were Level 3 fair value measurements and include key inputs such as forecasted contract prices, forecasted operating expenses and discount rates. During the fourth quarter of 2016, the Company recorded an additional impairment loss of $28 million for Ormond Beach. Wind Facilities — During the fourth quarter of 2016, as the Company updated its estimated future cash flows in connection with the preparation of its annual budget, the Company determined that the cash flows for the Elbow Creek and Goat Wind projects, located in Texas and the Forward project, located in Pennsylvania were below the carrying value of the related assets, primarily driven by the declining merchant power prices in post-contract periods, and the assets were considered impaired. The fair values of the facilities were determined using an income approach by applying a discounted cash flow methodology to the long-term budgets for each respective plant. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements and include key inputs, such as forecasted power prices, operations and maintenance expense and discount rates. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recorded impairment losses of $117 million , $60 million and $6 million for Elbow Creek, Goat Wind and Forward, respectively. Long Beach — During the fourth quarter of 2016, the Company determined that by the end of 2017 it would retire its Long Beach generation station located in Long Beach, California. The generating station was not awarded a PPA, in the SCE's capacity auction during the fourth quarter of 2016 and the current PPA will expire on July 31, 2017. The Company considered this to be an indicator of impairment and performed an impairment test. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recorded an impairment loss of $36 million . Keystone and Conemaugh Leased Interests — During the fourth quarter of 2016, the Company revised its estimated future cash flows in connection with the preparation of its annual budget. The Company noted the cash flows for the leased interests in Keystone and Conemaugh were below the carrying value of the related assets, primarily driven by a reduction in long-term energy and capacity prices in PJM, and the assets were impaired. The fair value of the interests in Keystone and Conemaugh were determined using the income approach which utilizes estimates of discounted future cash flows, which were Level 3 fair value measurements and include key inputs such as forecasted power, capacity and fuel prices, forecasted operating expenses, contractual lease payments and discount rates. The Company recorded impairment losses of $97 million and $10 million for Conemaugh and Keystone respectively, for the year ended December 31, 2016. Pittsburg — During the fourth quarter of 2016, the Company determined that it would need to retire the Pittsburg facility earlier than anticipated as it did not receive a resource adequacy contract for 2017. The Company considered this to be a triggering event and tested the assets for impairment. The fair value of the facility was determined using an income approach and the Company recorded an impairment loss of $20 million to reduce the carrying amount to the value of the underlying land. Other Impairments — During 2016, the Company recorded other impairment losses of $153 million , which included $23 million in excess SO 2 allowances, $23 million for other intangible assets, $19 million in previously purchased solar panels, $18 million in deferred marketing expenses, $22 million in other investments and $48 million of other impairment losses. Petra Nova Parish Holdings — During the first quarter of 2016, management changed its plans with respect to its future capital commitments driven in part by the continued decline in oil prices. As a result, the Company reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. 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 the fair value of the investment and recorded an impairment loss of $140 million . Community Wind North and Sherbino — During the fourth quarter of 2016, the Company offered several projects to NRG Yield including its interest in Community Wind North. The offer price was below its current carrying amount and this decline in fair value was determined to be other-than-temporary. Accordingly, the Company recorded an impairment loss of $36 million to reduce its carrying amount to fair value. In addition, in connection with the preparation of the annual budget, the Company noted that due to the anticipated difficulty in refinancing Sherbino’s debt that will mature in 2018, the project’s fair value had decreased significantly below its carrying amount and this decline was determined to be other-than-temporary. Accordingly, the Company determined that an other-than-temporary impairment existed and recorded an impairment loss on its investment in Sherbino of $70 million . 2015 Impairment Losses Seward — As described in Note 3 , Business Acquisitions and Dispositions , on November 24, 2015, the Company entered into an agreement with Robindale Energy Services, Inc. to sell Seward for cash consideration of $75 million . The transaction triggered an impairment indicator as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $134 million for the year ended December 31, 2015, to reduce the carrying amount of the assets held for sale to the fair market value. Limestone and W.A. Parish — During the fourth quarter of 2015, as the Company updated its estimates of future cash flows in connection with the preparation of its annual budget, it was noted that the cash flows for the Limestone and W.A. Parish coal-fired facilities located in Texas were lower than the carrying amount, primarily driven by declining power prices as the cost of commodities continues to decline and the assets were impaired. The fair value of the Limestone and W.A. Parish plants was determined using an income approach by applying a discounted cash flow methodology to the long-term budgets for each respective plant. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted power prices, fuel costs and emissions credit expense, forecasted operating and capital expenditures and discount rates. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recognized impairment losses of $1,514 million and $1,295 million related to Limestone and W.A. Parish, respectively. Huntley — On August 25, 2015, the Company filed a notice with the NYSPSC of its intent to retire Huntley's operating units on March 1, 2016. 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 . On October 14, 2015, the Company filed a cost-of-service filing at FERC in anticipation that the Huntley operating units would be needed for reliability purposes, proposing a reliability must run service agreement for a four-year period beginning on March 1, 2016. On October 30, 2015, NYISO released the results of its reliability study, indicating that the Huntley operating units are not needed for bulk system reliability. The Company considered the impact of the reliability study conducted and evaluated the estimated cash flows associated with the facility. Accordingly, the Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value of the Huntley operating units was determined using the income approach. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted contract prices, forecasted operating expenses and discount rates. The Company recorded an impairment loss of $132 million during the year ended December 31, 2015. Dunkirk — The Company signed a ten-year agreement in November 2014 with National Grid to add natural gas-burning capabilities at the Dunkirk facility. On August 25, 2015, NRG announced that Dunkirk Unit 2 would be mothballed on January 1, 2016 at the expiration of its reliability support services agreement. The project to add natural gas-burning capabilities has been suspended, pending the outcome of litigation with respect to the gas addition contract and its validity. On October 30, 2015, NYISO released the results of its reliability study, indicating that the Dunkirk facility is not needed for system reliability. In connection with the planned mothball of the facility, the pending litigation and the latest reliability assessment completed by NYISO, the Company evaluated whether the related fixed assets were impaired. The Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value of the Dunkirk facility was determined using the income approach. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted contract prices, forecasted operating and capital expenditures and discount rates. The Company recorded an impairment loss of $160 million during the year ended December 31, 2015. Gregory — During the fourth quarter of 2015, the Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value of the Gregory facility was determined using the income approach, which utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted prices, operating and capital expenditures and discount rates. The Company recorded an impairment loss of $176 million during the year ended December 31, 2015. Solar Panels — During the fourth quarter of 2015, the Company recorded an impairment loss of $29 million to reduce the carrying value of certain solar panels to their approximate fair value. Investments — During the fourth quarter of 2015, the Company reviewed certain of its cost method and equity method investments and concluded that losses incurred by these investments were other-than-temporary. These losses were primarily driven by the sustained decline in stock price of a publicly traded investment as well as change in financing structures of certain non-publicly traded investments. As a result, the Company recorded losses related to these investments of $56 million . 2014 Impairment Losses Coolwater — During the fourth quarter of 2014, the Company determined that it would retire the 636 MW natural-gas fired Coolwater facility in Dagget, California. The facility faced critical repairs on the cooling towers for units 3 and 4 and, during the fourth quarter of 2014, did not receive any awards in a near-term capacity auction and no interest in a bilateral capacity deal. 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 higher than the future net cash flows expected to be generated by the assets and as a result, the assets are considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets. The Company retired the Coolwater facility effective January 1, 2015. All remaining fixed assets of the station were written off resulting in an impairment loss of $22 million recorded during the fourth quarter of 2014. Osceola — During the third quarter of 2014, the Company determined that it would mothball the 463 MW natural gas-fired Osceola facility, in Saint Cloud, Florida. 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 higher than the future net cash flows expected to be generated by the assets and as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets. Due to the location of the facility, it was determined that the best indicator of fair value is the market value of the combustion turbines. The Company recorded an impairment loss of approximately $60 million during the third quarter of 2014, which represents the excess of the carrying value over the fair market value. Solar Panels — During the third quarter of 2014, the Company recorded an impairment loss of $10 million to reduce the carrying value of certain solar panels to their approximate fair value.

Goodwill and Other Intangibles

Goodwill and Other Intangibles (Notes)	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangibles	Goodwill and Other Intangibles Goodwill NRG's goodwill balance was $662 million and $999 million as of December 31, 2016 and 2015 , respectively. As of December 31, 2016 , and 2015 , NRG had approximately $547 million and $620 million , respectively, of goodwill that is deductible for U.S. income tax purposes in future periods. As of December 31, 2016, goodwill consisted of $276 million associated with the acquisition of EME, $341 million for Retail business acquisitions, and $45 million associated with other business acquisitions. 2016 Impairments of Goodwill During the year ended December 31, 2016, the Company recorded a goodwill impairment charge of $337 million related to its Texas reporting unit, reducing the goodwill balance for Texas to zero . In connection with the annual impairment assessment, the Company performed step one of the two-step impairment test for the Texas reporting unit, for which $1.7 billion of goodwill was recognized as part of the Texas Genco acquisition in 2006 and $1.4 billion was written off in 2015. The Company determined the fair value of the Texas reporting unit primarily using an income approach through which the Company applied a discounted cash flow methodology to the long-term budgets for all plants in the regions. Significant inputs impacting the income approach include the Company's views of power and fuel prices for the first five-year period and the Company's view for the longer term, which were finalized in connection with the preparation of the fourth quarter financial statements, projected generation based on an hourly dispatch meant to simulate the dispatch of each unit into the power market which is impacted by power prices, fuel prices, and the physical and economic characteristics of each plant, intangible value to Texas for synergies it provides to NRG's retail businesses, and the discount rate applied to cash flow projections. Under step one, the estimated fair value of the Texas invested capital was 43% below its carrying value as of December 31, 2016, and the Company concluded step two was required. Based on the results of step two of the impairment test, the Company determined the carrying amount of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $337 million as of December 31, 2016. 2015 Impairments of Goodwill During the year ended December 31, 2015 , the Company recorded goodwill impairment charges of $1.5 billion which are comprised of the following: Texas — In connection with the annual impairment assessment, the Company performed step one of the two-step impairment test for the Texas reporting unit, for which $1.7 billion of goodwill was recognized as part of the Texas Genco acquisition in 2006. The Company determined the fair value of the Texas reporting unit primarily using an income approach through which the Company applied a discounted cash flow methodology to the long-term budgets for all plants in the regions. Significant inputs impacting the income approach include the Company's views of power and fuel prices for the first five-year period and the Company's view for the longer term, which were finalized in connection with the preparation of the fourth quarter financial statements, projected generation based on an hourly dispatch meant to simulate the dispatch of each unit into the power market which is impacted by power prices, fuel prices, and the physical and economic characteristics of each plant, intangible value to Texas for synergies it provides to NRG's retail businesses, and the discount rate applied to cash flow projections. Under step one, the estimated fair value of the Texas invested capital was 76% below its carrying value as of December 31, 2015, and the Company concluded step two was required. Based on the results of step two of the impairment test, the Company determined the carrying amount of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $1.4 billion as of December 31, 2015. NRG Home Solar — The Company performed the two-step impairment test as part of its annual impairment testing for the NRG Home Solar reporting unit utilizing an income approach developed through applying a discounted cash flow methodology to the long-term budget for the reporting unit. As a result, the Company determined that the carrying value of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $125 million during the year ended December 31, 2015 to reduce the carrying value of the goodwill that was recognized in connection with acquisitions made by NRG Home Solar. Goal Zero — During the third quarter of 2015, the Company agreed to relieve the Goal Zero seller of all known and unknown claims in return for the seller's agreement to forego all contingent consideration. Concurrently, the Company determined that there was an indication of goodwill impairment and performed an impairment test . The carrying amount of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $36 million during the third quarter of 2015 to reduce the carrying value of the goodwill that was recognized in connection with the acquisition. Intangible Assets The Company's intangible assets as of December 31, 2016 , primarily reflect intangible assets established with the acquisitions of various companies and are comprised of the following: • Emission Allowances — These intangibles primarily consist of SO 2 and NO x 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 NO x allowances amortized on a straight-line basis and SO 2 allowances and RGGI credits amortized based on units of production. During the year ended December 31, 2016, the Company recorded an impairment loss of $23 million to reduce the value of excess SO 2 allowances to zero. • 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 Dominion, 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. During the year ended December 31, 2016, the Company recorded an impairment loss of $8 million for certain customer relationships. • Marketing partnerships — Established with the acquisition of Energy Plus, 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, Energy Plus and Dominion acquisitions, these intangibles are amortized to depreciation and amortization expense, on a straight-line basis. • Power purchase agreements — Established predominantly with the EME and Alta Wind acquisitions, these represent the fair value of PPAs acquired. These will be amortized to revenues, generally on a straight-line basis, over the terms of the PPAs. • Other — Consists of renewable energy credits, wind leasehold rights, costs to extend the operating license for STP Units 1 and 2, and the intangible asset related to a purchased ground lease. During the year ended December 31, 2016, the Company recorded an impairment loss of $15 million of other intangible assets. The following tables summarize the components of NRG's intangible assets subject to amortization: Contracts Year Ended December 31, 2016 Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) January 1, 2016 $ 920 $ 54 $ 72 $ 16 $ 834 $ 88 $ 342 $ 1,264 $ 245 $ 3,835 Purchases 50 — — — — — — — 34 84 Acquisition of businesses — — — — — — — — 18 18 Usage (1 ) — — — — — — — (44 ) (45 ) Write-off of fully amortized balances (a) (10 ) — — — — — — — — (10 ) Impairment (b) (23 ) — — — (18 ) — — — (23 ) (64 ) Other (7 ) — — — — — — — — (7 ) December 31, 2016 929 54 72 16 816 88 342 1,264 230 3,811 Less accumulated amortization (605 ) (54 ) (67 ) (8 ) (663 ) (49 ) (159 ) (138 ) (32 ) (1,775 ) Net carrying amount $ 324 $ — $ 5 $ 8 $ 153 $ 39 $ 183 $ 1,126 $ 198 $ 2,036 (a) Adjusted for write-off of fully amortized emission allowances of $10 million . (b) The impairment of customer relationships and other intangibles included a write-off of accumulated amortization of $10 million and $8 million respectively. Contracts Year Ended December 31, 2015 Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) January 1, 2015 $ 1,018 $ 54 $ 72 $ 16 $ 831 $ 88 $ 353 $ 1,270 $ 267 $ 3,969 Purchases 77 — — — 3 — — — 57 137 Usage (33 ) — — — — — — — (62 ) (95 ) Write-off of fully amortized balances (154 ) — — — — — — — — (154 ) Impairment — — — — — — (6 ) — (5 ) (11 ) Other 12 — — — — — (5 ) (6 ) (12 ) (11 ) December 31, 2015 920 54 72 16 834 88 342 1,264 245 3,835 Less accumulated amortization (a) (502 ) (47 ) (65 ) (6 ) (624 ) (41 ) (137 ) (75 ) (28 ) (1,525 ) Net carrying amount $ 418 $ 7 $ 7 $ 10 $ 210 $ 47 $ 205 $ 1,189 $ 217 $ 2,310 (a) Adjusted for write-off of fully amortized emission allowances of $154 million . The following table presents NRG's amortization of intangible assets for each of the past three years: Years Ended December 31, Amortization 2016 2015 2014 (In millions) Emission allowances $ 113 $ 99 $ 124 Energy supply contracts 7 5 6 Fuel contracts 2 2 2 Customer contracts 2 2 — Customer relationships 49 67 70 Marketing partnerships 8 14 15 Trade names 22 23 21 Power purchase agreements 63 50 24 Other 12 15 6 Total amortization $ 278 $ 277 $ 268 The following table presents estimated amortization of NRG's intangible assets for each of the next five years: Contracts Year Ended December 31, Emission Allowances Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) 2017 $ 82 $ 1 $ 1 $ 26 $ 5 $ 23 $ 57 $ 3 $ 198 2018 33 — 1 14 5 23 57 3 136 2019 31 — 1 10 4 23 57 3 129 2020 16 — 1 8 4 23 57 3 112 2021 16 — 1 6 4 23 57 3 110 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, 2016 , the value of emission allowances held-for-sale is $39 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 $159 million and $790 million acquired in the acquisitions of EME and GenOn, respectively, 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. As of December 31, 2016 and 2015, the Company had accumulated amortization for out-of-market contracts of $765 million and $664 million . 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) 2017 $ 16 47 $ 37 $ 100 2018 16 47 32 95 2019 17 47 29 93 2020 17 47 29 93 2021 10 47 26 83

Debt and Capital Leases (Notes)

Debt and Capital Leases (Notes)	12 Months Ended
	Dec. 31, 2016
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, December 31, 2016 2016 2015 Interest Rate % (a) (In millions except rates) NRG Recourse Debt: Senior notes, due 2018 $ 398 $ 1,039 7.625 Senior notes, due 2020 — 1,058 8.250 Senior notes, due 2021 207 1,128 7.875 Senior notes, due 2022 992 1,100 6.250 Senior notes, due 2023 869 936 6.625 Senior notes, due 2024 733 904 6.250 Senior notes, due 2026 1,000 — 7.250 Senior notes, due 2027 1,250 — 6.625 Term loan facility, due 2018 — 1,964 L+2.00 Term loan facility, due 2023 1,882 — L+2.75 Tax-exempt Bonds 455 455 4.125 - 6.00 Subtotal NRG Recourse Debt 7,786 8,584 NRG Non-Recourse Debt: GenOn senior notes 1,911 1,956 7.875 - 9.875 GenOn Americas Generation senior notes 745 752 8.500 - 9.125 GenOn Other 96 56 Subtotal GenOn debt (non-recourse to NRG) 2,752 2,764 NRG Yield Operating LLC Senior Notes, due 2024 500 500 5.375 NRG Yield Operating LLC Senior Notes, due 2026 350 — 5.000 NRG Yield LLC and Yield Operating LLC Revolving Credit Facility, due 2019 — 306 L+2.75 NRG Yield Inc. Convertible Senior Notes, due 2019 335 330 3.500 NRG Yield Inc. Convertible Senior Notes, due 2020 271 266 3.250 El Segundo Energy Center, due 2023 443 485 L+1.625 - L+2.25 Marsh Landing, due 2017 and 2023 370 418 L+1.75 - L+1.875 Alta Wind I-V lease financing arrangements, due 2034 and 2035 965 1,002 5.696 - 7.015 Walnut Creek, term loans due 2023 310 351 L+1.625 Tapestry, due 2021 172 181 L+1.625 CVSR, due 2037 771 793 2.339 - 3.775 CVSR HoldCo, due 2037 199 — 4.680 Alpine, due 2022 145 154 L+1.750 Energy Center Minneapolis, due 2017 and 2025 96 108 5.95 - 7.25 Energy Center Minneapolis, due 2031 125 — 3.55 Viento, due 2023 178 189 L+2.75 NRG Yield - other 540 573 various Subtotal NRG Yield debt (non-recourse to NRG) 5,770 5,656 Ivanpah, due 2033 and 2038 1,113 1,149 2.285 - 4.256 Agua Caliente, due 2037 849 879 2.395 - 3.633 Dandan, due 2033 76 98 L+2.25 Peaker bonds, due 2019 — 72 L+1.07 Cedro Hill, due 2025 163 103 L+1.75 Utah Portfolio, due 2022 287 — L+2.65 Midwest Generation, due 2019 218 — 4.390 NRG Other 392 315 various Subtotal other NRG non-recourse debt 3,098 2,616 Subtotal all non-recourse debt 11,620 11,036 Subtotal long-term debt (including current maturities) 19,406 19,620 Capital leases: 8 16 various Subtotal long-term debt and capital leases (including current maturities) 19,414 19,636 Less current maturities 1,220 481 Less debt issuance costs 188 172 Total long-term debt and capital leases $ 18,006 $ 18,983 (a) As of December 31, 2016 , L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%. Long-term debt includes the following premiums/(discounts): As of December 31, 2016 2015 (In millions) Term loan facility, due 2018 (a) $ — $ (3 ) Term loan facility, due 2023 (a) (9 ) — Peaker bonds, due 2019 (b) — (4 ) Yield, Inc. Convertible notes, due 2019 (10 ) (15 ) Yield, Inc. Convertible notes, due 2020 (17 ) (21 ) Midwest Generation, due 2019 (13 ) — GenOn senior notes, due 2017 (c) 8 23 GenOn senior notes, due 2018 (c) 38 59 GenOn senior notes, due 2020 (c) 35 44 GenOn Americas Generation senior notes, due 2021 (c) 26 32 GenOn Americas Generation senior notes, due 2031 (c) 24 25 Total premium $ 82 $ 140 (a) Term loan facility, due 2018 replaced with the Term loan facility due 2023. Discount of $1 million was related to current maturities in 2016. (b) Repaid in 2016. (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. Consolidated Annual Maturities Annual payments based on the maturities of NRG's debt and capital leases for the years ending after December 31, 2016 are as follows: (In millions) 2017 $ 1,222 2018 1,650 2019 839 2020 1,273 2021 1,157 Thereafter 13,192 Total $ 19,333 NRG Recourse Debt Senior Notes Issuance of 2026 Senior Notes On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026. The proceeds from the issuance of the 2026 Senior Notes were utilized to repurchase a portion of the Senior Notes discussed below under 2016 Senior Note Repurchases . Issuance of 2027 Senior Notes On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the 2027 Senior Notes. The 2027 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on January 15, 2017, until the maturity date of January 15, 2027. The proceeds from the issuance of the 2027 Senior Notes were utilized to retire the Company's 8.250% senior notes due 2020 and reduce the balance of the Company's 7.875% senior notes due 2021. 2016 Senior Notes Repurchases During the year ended December 31, 2016, the Company repurchased $3.0 billion in aggregate principal of its Senior Notes for $3.1 billion , which included accrued interest of $77 million . In connection with the repurchases, a $117 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $16 million . Principal Repurchased Cash Paid (a) Average Early Redemption Percentage Amount in millions, except rates 7.625% senior notes due 2018 (b) $ 641 $ 706 107.89 % 8.250% senior notes due 2020 1,058 1,129 103.12 % 7.875% senior notes due 2021 (c) 922 978 104.00 % 6.250% senior notes due 2022 108 105 94.73 % 6.625% senior notes due 2023 67 64 94.13 % 6.250% senior notes due 2024 171 163 94.52 % Total $ 2,967 $ 3,145 (a) Includes payment for accrued interest. (b) $186 million of the redemptions financed by cash on hand. (c) $193 million of the redemptions financed by cash on hand. 2015 Senior Notes Repurchases During the year ended December 31, 2015, the Company repurchased $246 million in aggregate principal of its Senior Notes for $231 million , which included accrued interest of $5 million . In connection with the repurchases, a $19 million gain on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $2 million . Principal Repurchased Cash Paid (a) Average Early Redemption Percentage Amount in millions, except rates 7.625% senior notes due 2018 $ 92 $ 97 102.23 % 8.250% senior notes due 2020 5 5 96.50 % 6.625% senior notes due 2023 54 47 85.97 % 6.250% senior notes due 2024 95 82 84.73 % Total $ 246 $ 231 (a) Includes payment for accrued interest. Senior Notes Outstanding As of December 31, 2016 , NRG had seven outstanding issuances of senior notes, or Senior Notes: i. 7.875% senior notes, issued May 24, 2011 and due May 15, 2021, or the 2021 Senior Notes; ii. 6.625% senior notes, issued September 24, 2012 and due March 15, 2023, or the 2023 Senior Notes; iii. 6.250% senior notes, issued January 27, 2014 and due July 15, 2022, or the 2022 Senior Notes; iv. 6.250% senior notes, issued April 21, 2014 and due November 1, 2024, or the 2024 Senior Notes; v. 7.250% senior notes, issued May 23, 2016 and due May 15, 2026, or the 2026 Senior Notes; and vi. 6.625% senior notes, issued August 2, 2016 and due January 15, 2027, or the 2027 Senior Notes. vii. 7.625% senior notes, issued January 26, 2011 and due January 15, 2018, or the 2018 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 forms 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. 2021 Senior Notes 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 100.000 % 2022 Senior Notes At any time prior to July 15, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to July 15, 2018, NRG may redeem all or a part of the 2022 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. 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 103.125% of the note, plus interest payments due on the note from the date of redemption through July 15, 2018, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after July 15, 2018, 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 July 15, 2018 to July 14, 2019 103.125 % July 15, 2019 to July 14, 2020 101.563 % July 15, 2020 and thereafter 100.000 % 2023 Senior Notes 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 2023 Senior 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 100.000 % 2024 Senior Notes At any time prior to May 1, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2024 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to May 1, 2019, NRG may redeem all or a part of the 2024 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. 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 103.125% of the note, plus interest payments due on the note from the date of redemption through May 1, 2019 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after May 1, 2019, 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 1, 2019 to April 30, 2020 103.125 % May 1, 2020 to April 30, 2021 102.083 % May 1, 2021 to April 30, 2022 101.042 % May 1, 2022 and thereafter 100.000 % 2026 Senior Notes At any time prior to May 15, 2019, NRG may redeem up to 35% of the aggregate principal amount of the 2026 Senior Notes, at a redemption price equal to 107.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings . At any time prior to May 15, 2021, NRG may redeem all or a part of the 2026 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. 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 103.625% of the note, plus interest payments due on the note from the date of redemption through May 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after May 15, 2021, 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, 2021 to May 14, 2022 103.625 % May 15, 2022 to May 14, 2023 102.417 % May 15, 2023 to May 14, 2024 101.208 % May 15, 2024 and thereafter 100.000 % 2027 Senior Notes At any time prior to July 15, 2019, NRG may redeem up to 35% of the aggregate principal amount of the 2027 Senior Notes, at a redemption price equal to 106.625% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to July 15, 2021 NRG may redeem all or a part of the 2027 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. 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 July 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after July 15, 2021, 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 July 15, 2021 to July14, 2022 103.313 % July 15, 2022 to July 14, 2023 102.208 % July 15, 2023 to July 14, 2024 101.104 % July 15, 2024 and thereafter 100.000 % Senior Credit Facility On June 30, 2016, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility and Revolving Credit Facility with a new senior secured facility, or the 2016 Senior Credit Facility, which includes the following: • A $1.9 billion term loan facility, or the 2023 Term Loan Facility, with a maturity date of June 30, 2023, which will pay interest at a rate of LIBOR plus 2.75% , with a LIBOR floor of 0.75% . The debt was issued at 99.50% of face value; the discount will be amortized to interest expense over the life of the loan. Repayments under the 2023 Term Loan Facility will consist of 0.25% of principal per quarter, with the remainder due at maturity. The proceeds of the new term loan facility as well as cash on hand were used to repay the 2018 Term Loan Facility balance outstanding. A $21 million loss on extinguishment of the Term Loan Facility was recorded during the second quarter of 2016, which consisted of the write-off of previously deferred financing costs. On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25% , the LIBOR floor remains 0.75% . • A $289 million revolving senior credit facility, or the Tranche A Revolving Facility, with a maturity date of July 1, 2018 and a $2.2 billion revolving senior credit facility, or the Tranche B Revolving Facility, with a maturity date of June 30, 2021, which will pay interest at a rate of LIBOR plus 2.25% . The 2016 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, and certain other subsidiaries, including GenOn, NRG Yield, Inc. and their respective subsidiaries. The capital stock of these guarantor subsidiaries has been pledged for the benefit of the 2016 Senior Credit Facility's lenders. The 2016 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, NRG Yield, Inc. and their respective subsidiaries, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG's foreign subsidiaries. Tax Exempt Bonds As of December 31, 2016 2015 Interest Rate % Amount in millions, except rates Indian River Power tax exempt bonds, due 2040 $ 57 $ 57 6.000 Indian River Power LLC, tax exempt bonds, due 2045 190 190 5.375 Dunkirk Power LLC, tax exempt bonds, due 2042 59 59 5.875 City of Texas City, tax exempt bonds, due 2045 22 22 4.125 Fort Bend County, tax exempt bonds, due 2038 54 54 4.750 Fort Bend County, tax exempt bonds, due 2042 73 73 4.750 Total $ 455 $ 455 NRG Non-Recourse Debt The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2016 . 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, 2016 , NRG had net assets of $4.9 billion that were deemed restricted for purposes of Rule 4-08(e)(3)(ii) of Regulation S-X. The indebtedness described below is non-recourse to NRG, unless otherwise noted. GenOn Senior Notes As of December 31, 2016 2015 Interest Rate % Amount in millions, except rates Senior unsecured notes, due 2017 $ 699 $ 714 7.875 Senior unsecured notes, due 2018 687 708 9.500 Senior unsecured notes, due 2020 525 534 9.875 Total $ 1,911 $ 1,956 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. 2015 Repurchase of GenOn Senior Notes During the fourth quarter of 2015, the Company repurchased $119 million in aggregate principal of the following outstanding Senior Notes for $108 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain on Debt Extinguishment Amount in millions, except rates Senior unsecured notes, due 2017 $ 33 95.172 % $ 3 Senior unsecured notes, due 2018 25 90.950 % 5 Senior unsecured notes, due 2020 61 83.847 % 15 Total $ 119 $ 23 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 and purchases of capital stock. 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, 2016 , GenOn failed the consolidated debt ratio component of the restricted payments test. Under the related indentures, 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, 2016 , GenOn net assets of $368 million were deemed restricted for purposes of Rule 4-08(e)(3)(ii) 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. GenOn may redeem some or all of the Senior Notes due 2020 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, 2016 to October 14, 2017 103.292 % October 15, 2017 to October 14, 2018 101.646 % October 15, 2018 and thereafter 100.000 % 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 . GenOn Americas Generation Senior Notes As of December 31, 2016 2015 Interest Rate % Amount in millions, except rates Senior unsecured notes, due 2021 $ 392 $ 398 8.500 Senior unsecured notes, due 2031 353 354 9.125 Total $ 745 $ 752 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. 2015 Repurchase of GenOn Americas Generation Senior Notes During the fourth quarter of 2015, the Company repurchased $155 million in aggregate principal of the following outstanding Senior Notes for $128 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain on Debt Extinguishment Amount in millions, except rates Senior unsecured notes, due 2021 $ 84 84.910 % $ 20 Senior unsecured notes, due 2031 71 77.018 % 22 Total $ 155 $ 42 2021 and 2031 GenOn Americas Senior Notes 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. Yield Operating LLC Senior Notes 2024 Yield Operating Senior Notes On August 5, 2014, Yield Operating issued $500 million of senior unsecured notes and utilized the proceeds to fund the acquisition of the Alta Wind Assets. The Yield Operating senior notes bear interest at 5.375% and mature in August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year, and commenced on February 15, 2015. The notes are senior unsecured obligations of Yield Operating and are guaranteed by NRG Yield LLC, Yield Operating’s parent company, and by certain of Yield Operating’s wholly owned current and future subsidiaries. Yield LLC and Yield Operating LLC Revolving Credit Facility NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. At December 31, 2016, there was $60 million of letters of credit issued under the revolving credit facility and no borrowing outstanding on the revolver. Yield, Inc. Convertible Notes 2020 Yield Inc. Convertible Notes On June 29, 2015, NRG Yield, Inc. closed on its offering of $287.5 million aggregate principal amount of 3.25% Convertible Senior Notes due 2020, or the 2020 Convertible Notes. The 2020 Convertible Notes are convertible, under certain circumstances, into NRG Yield, Inc. Class C common stock, cash or a combination thereof at an initial conversion price of $27.50 per Class C common share, which is equivalent to an initial conversion rate of approximately 36.3636 shares of Class C common stock per $1,000 principal amount of notes. Interest on the 2020 Convertible Notes is payable semi-annually in arrears on June 1 and December 1 of each year, commencing on December 1, 2015. The 2020 Convertible Notes mature on June 1, 2020, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding December 1, 2019, the 2020 Convertible 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. The 2020 Convertible Notes are accounted for in accordance with ASC 470-20, under which issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The equity component, the $23 million conversion option value, was recorded to NRG's noncontrolling interest for NRG Yield, Inc. with the offset to debt discount. The debt discount is being amortized to interest expense over the term of the notes. 2019 Yield Inc. Convertible Notes In the first quarter of 2014, NRG Yield, Inc. closed on its offering of $345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019, or the 2019 Convertible Notes. The 2019 Convertible Notes were convertible, under certain circumstances, into NRG Yield, Inc. Class A 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 2019 Convertible Notes. Effective May 15, 2015, the conversion rate was adjusted to 42.9644 shares of Class A common stock per $1,000 principal amount of 2019 Convertible Notes in accordance with the terms of the related indenture. Interest on the 2019 Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2014. The 2019 Convertible Notes 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 2019 Convertible 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. The 2019 Convertible Notes are accounted for in accordance with ASC 470-20. The equity component, the $23 million conversion option value, was recorded to NRG's noncontrolling interest for NRG Yield, Inc. with the offset to debt discount. The debt discount is being amortized to interest expense over the term of the notes. The 2019 Convertible Notes are guaranteed by NRG Yield Operating LLC and NRG Yield LLC. NRG Yield Operating 2026 Senior Notes On August 18, 2016, NRG Yield Operating LLC issued $350 million of senior unsecured notes, or the NRG Yield Operating 2026 Senior Notes. The NRG Yield Operating 2026 Senior Notes bear interest of 5.00% and mature on September 15, 2026. Interest on the notes is payable semi-annually on March 15 and September 15 of each year, and will commence on March 15, 2017. The Yield Operating 2026 Senior Notes are senior unsecured obligations of NRG Yield Operating LLC and are guaranteed by NRG Yield LLC, and by certain of NRG Yield Operating LLC’s wholly owned current and future subsidiaries. A portion of the proceeds from the 2026 Senior Notes was used to repay NRG Yield Operating LLC's revolving credit facility. Project Financings The following are descriptions of certain indebtedness of NRG's project subsidiaries that are outstanding as of December 31, 2016 . Aqua Caliente Holdco Financing Agreement On February 17, 2017, Agua Caliente Borrower I LLC and Agua Caliente Borrower II LLC, Agua Caliente Holdco, the indirect owners of the Agua Caliente solar facility, issued $130 million of senior secured notes under the Agua Caliente Holdco Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at 5.43% and mature on December 31, 2038. Net proceeds were distributed to the Company. Utah Portfolio As part of the 2016 utility-scale solar and wind acquisition on November 2, 2016, as discussed in Note 3 , Business Acquisitions and Dispositions , NRG recorded $222 million of non-recourse project level debt. As of term conversion for the three associated debt facilities, the Company borrowed an additional $65 million of non-recourse debt. Each facility bears interest of LIBOR plus 2.625% and matures on December 16, 2022. Thermal Financing On October 31, 2016, NRG Energy Center Minneapolis LLC, a subsidiary of NRG Yield, Inc., received proceeds of $125 million from the issuance of 3.55% Series D notes due October 31, 2031, or the Series D Notes, and entered into a shelf facility for the anticipated issuance of an additional $70 million of notes. The Series D Notes are secured by substantially all of the assets of NRG Energy Center Minneapolis LLC. NRG Thermal LLC has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal LLC’s subsidiaries. NRG Energy Center Minneapolis LLC distributed the proceeds of the Series D Notes to NRG Thermal LLC, who in turn distributed the proceeds to NRG Yield Operating LLC to be utilized for general corporate purposes, including potential acquisitions. Alta Wind X and Alta Wind XI due 2021 On June 30, 2015, the Company entered into a tax equity financing arrangement through which Yield Operating, a subsidiary of NRG Yield, Inc., received $119 million in net proceeds. These proceeds, as well as proceeds obtained from the June 29, 2015, NRG Yield

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company'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, the Company 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 the Company'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, 2016 and 2015 , along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2016 : (In millions) Balance as of December 31, 2015 $ 945 Revisions in estimates for current obligations (103 ) Additions 49 Spending for current obligations (8 ) Accretion — Expense 42 Accretion — Nuclear decommissioning 15 Balance as of December 31, 2016 $ 940

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefit Plans (Notes)	12 Months Ended
	Dec. 31, 2016
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 in 2012, 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 $36 million to the Company's pension plans in 2017 . 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 decided to terminate/settle the nonqualified legacy GenOn Benefit Restoration Plan and Supplemental Executive Retirement Plan. Final settlement payments totaling $12 million were paid to remaining participants during 2014. On December 31, 2014, NRG merged eight qualified pension plans into two separate qualified pension plans, the NRG Pension Plan for Bargained Employees and the NRG Pension Plan. The NRG Pension Plan for Bargained Employees, GenOn Mirant Bargaining Unit Pension Plan, GenOn First Energy Pension Plan, GenOn Duquesne Pension Plan, and GenOn REMA Pension Plan were merged into the NRG Pension Plan for Bargained Employees. The NRG Texas Retirement Plan, and GenOn Mirant Pension Plan were merged into the NRG Pension Plan for Non-Bargained Employees and renamed the NRG Pension Plan. These actions were conducted to simplify internal administration of the plans, reduce regulatory filings, and lower fees paid to outside vendors. The benefits provided to current participants in the Plans were not impacted. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including pension liabilities associated with GenOn employees. NRG Defined Benefit Plans The annual net periodic benefit cost/(credit) related to NRG's pension and other postretirement benefit plans include the following components: Year Ended December 31, Pension Benefits 2016 2015 2014 (In millions) Service cost benefits earned $ 30 $ 32 $ 30 Interest cost on benefit obligation 43 53 53 Expected return on plan assets (60 ) (62 ) (62 ) Amortization of unrecognized net loss/(gain) 2 2 (6 ) Net periodic benefit cost $ 15 $ 25 $ 15 Year Ended December 31, Other Postretirement Benefits 2016 2015 2014 (In millions) Service cost benefits earned $ 2 $ 3 $ 3 Interest cost on benefit obligation 6 9 9 Amortization of unrecognized prior service credit (5 ) (5 ) (17 ) Amortization of unrecognized net loss — 1 — Curtailment gain — (14 ) — Net periodic benefit cost/(credit) $ 3 $ (6 ) $ (5 ) 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 2016 2015 2016 2015 (In millions) Benefit obligation at January 1 $ 1,196 $ 1,305 $ 178 $ 238 Service cost 30 32 2 3 Interest cost 43 53 6 9 Plan amendments — — (42 ) (6 ) Actuarial loss/(gain) 40 (120 ) (2 ) (31 ) Employee and retiree contributions — — 3 2 Benefit payments (68 ) (74 ) (17 ) (12 ) Curtailment — — — (25 ) Benefit obligation at December 31 1,241 1,196 128 178 Fair value of plan assets at January 1 916 988 — — Actual return on plan assets 72 (26 ) — — Employee and retiree contributions — — 3 2 Employer contributions 33 28 14 10 Benefit payments (68 ) (74 ) (17 ) (12 ) Fair value of plan assets at December 31 953 916 — — Funded status at December 31 — excess of obligation over assets $ (288 ) $ (280 ) $ (128 ) $ (178 ) Amounts recognized in NRG's balance sheets were as follows: As of December 31, Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 (In millions) Current liabilities $ — $ — $ 8 $ 12 Non-current liabilities 288 280 120 166 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 2016 2015 2016 2015 (In millions) Net loss/(gain) $ 94 $ 68 $ (11 ) $ (9 ) Prior service cost/(credit) 3 3 (45 ) (9 ) Other changes in plan assets and benefit obligations recognized in OCI were as follows: Year Ended December 31, Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 (In millions) Net actuarial loss/(gain) $ 28 $ (31 ) $ (2 ) $ (31 ) Amortization of net actuarial (gain)/loss (2 ) (2 ) — (1 ) Prior service credit — (1 ) (41 ) (7 ) Amortization of prior service cost — — 5 5 Curtailment — — — (11 ) Total recognized in other comprehensive loss/(income) $ 26 $ (34 ) $ (38 ) $ (45 ) Total recognized in net periodic pension cost/(credit) and other comprehensive loss/(income) $ 41 $ (8 ) $ 36 $ (37 ) The Company's estimated unrecognized loss 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 $4 million . The Company's estimated unrecognized gain and unrecognized prior service credit for NRG's postretirement plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is $1 million and $8 million , respectively. The following table presents the balances of significant components of NRG's pension plan: As of December 31, Pension Benefits 2016 2015 (In millions) Projected benefit obligation $ 1,241 $ 1,196 Accumulated benefit obligation 1,174 1,115 Fair value of plan assets 953 916 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, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total (In millions) Common/collective trust investment — U.S. equity $ — $ 283 $ 283 Common/collective trust investment — non-U.S. equity — 149 149 Common/collective trust investment — global equity — 104 104 Common/collective trust investment — fixed income — 383 383 Partnerships/joint ventures — 31 31 Short-term investment fund 3 — 3 Total $ 3 $ 950 $ 953 Fair Value Measurements as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total (In millions) Common/collective trust investment — U.S. equity $ — $ 255 $ 255 Common/collective trust investment — non-U.S. equity — 147 147 Common/collective trust investment — global equity — 90 90 Common/collective trust investment — fixed income — 400 400 Partnerships/joint ventures — 18 18 Short-term investment fund 6 — 6 Total $ 6 $ 910 $ 916 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 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. Partnerships/joint ventures Level 2 investments consist primarily of a partnership which invests in emerging market equity securities. 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 2016 2015 2016 2015 Discount rate 4.26 % 4.52 % 4.29 % 4.55 % Rate of compensation increase 3.00 % 3.00 % N/A N/A Health care trend rate — — 7.0% grading to 5.0% in 2025 7.25% grading to 5.0% in 2025 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 2016 2015 2014 2016 2015 2014 Discount rate 4.52 % 4.16 % 4.99 % 4.55 % 4.20 % 5.06 % Expected return on plan assets 6.65 % 6.36 % 6.81 % — — — Rate of compensation increase 3.00 % 3.45 % 3.65 % — — — Health care trend rate — — — 7.25% grading to 5.0% in 2025 8.6% grading to 5.0% in 2023 8.5% grading to 5.5% 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 defined benefit retirement plans as of December 31. The discount rate assumptions represent the current rate at which the associated liabilities could be effectively settled at December 31. The Company utilizes the Aon Hewitt AA Above Median, or AA-AM, yield curve to select the appropriate discount rate assumption for each retirement plan. The AA-AM yield curve is a hypothetical AA yield curve represented by a series of annualized individual spot discount rates from 6 months to 99 years. Each bond issue used to build this yield curve must be non-callable, and have an average rating of AA when averaging available Moody's Investor Services, Standard & Poor's and Fitch ratings. 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 assumption 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. In 2016, NRG changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and postretirement benefit plans. Historically, the Company estimated these components by using a single weighted average discount rate derived from the yield curve used to measure the benefit obligation. The Company has elected to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the yield curve to the relevant projected cash flows, as this provides a better estimate of service and interest costs. This election is considered a change in estimate and, accordingly, has been accounted for starting in 2016. This change does not affect the measurement of NRG's total benefit obligation. The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2016 : U.S. equity 27 % Non-U.S. equity 15 % Global equity 10 % Emerging market equity 3 % U.S. fixed income 45 % Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S., non-U.S., global, and emerging market equities, as well as among growth, value, small and large capitalization stocks. Investment risk and performance are monitored on an ongoing basis through quarterly portfolio reviews of each asset fund class to a related performance benchmark, if applicable, and annual pension liability measurements. Performance benchmarks are composed of the following indices: Asset Class Index U.S. equities Dow Jones U.S. Total Stock Market Index Non-U.S. equities MSCI All Country World Ex-U.S. IMI Index Global equities MSCI World Index Emerging market equities MSCI Emerging Markets Index Fixed income securities Barclays Capital Long Term Government/Credit Index & Barclays Strips 20+ Index 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 Benefit Payments Medicare Prescription Drug Reimbursements (In millions) 2017 $ 66 $ 8 $ — 2018 69 8 — 2019 72 8 — 2020 76 9 — 2021 79 9 — 2022-2026 417 38 1 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- Point Increase 1-Percentage- Point Decrease (In millions) Effect on total service and interest cost components $ 1 $ — Effect on postretirement benefit obligation 9 (8 ) 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 year ended December 31, 2016 , NRG reimbursed STPNOC $7 million towards its defined benefit plans. For the year ended December 31, 2015, NRG reimbursed STPNOC $9 million towards its defined benefit plans. In 2017 , NRG expects to reimburse STPNOC $12 million for its contribution 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 2016 2015 2016 2015 (In millions) Funded status — STPNOC benefit plans $ (74 ) $ (63 ) $ (23 ) $ (26 ) Net periodic benefit cost/(credit) 7 10 (2 ) (8 ) Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss) 11 (8 ) (1 ) 6 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, 2016 2015 2014 (In millions) Company contributions to defined contribution plans $ 55 $ 53 $ 47

Capital Structure (Notes)

Capital Structure (Notes)	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Capital Structure	Capital Structure For the period from December 31, 2013 to December 31, 2016 , the Company had 10,000,000 shares of preferred stock authorized, and 500,000,000 shares of common stock authorized. 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, 2013 401,126,780 (77,347,528 ) 323,779,252 Shares issued under ESPP — 128,336 128,336 Shares issued under LTIPs 1,707,419 — 1,707,419 Shares issued in connection with the EME acquisition 12,671,977 — 12,671,977 Share repurchases — (1,624,360 ) (1,624,360 ) Balance as of December 31, 2014 415,506,176 (78,843,552 ) 336,662,624 Shares issued under ESPP — 283,139 283,139 Shares issued under LTIPs 1,433,774 — 1,433,774 Share repurchases — (24,189,495 ) (24,189,495 ) Balance as of December 31, 2015 416,939,950 (102,749,908 ) 314,190,042 Shares issued under ESPP — 609,094 609,094 Shares issued under LTIPs 643,875 — 643,875 Balance as of December 31, 2016 417,583,825 (102,140,814 ) 315,443,011 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 the long-term incentive plans as of December 31, 2016 : Equity Instrument Common Stock Reserve Balance Long-term incentive plans 17,336,092 Common stock dividends — In 2014, NRG paid quarterly dividends on the Company's common stock of $0.14 per share, or $0.56 per share on an annualized basis. In 2015 , the Company increased its annual common stock dividend by 4% to $0.58 per share and in 2016 , as part of the 2016 Capital Allocation Program, the Company decreased its annual common stock dividend by 79% to $0.12 per share. The following table lists the dividends paid per common share during 2016 , 2015 and 2014 : Fourth Quarter Third Quarter Second Quarter First Quarter 2016 $ 0.030 $ 0.030 $ 0.030 $ 0.145 2015 $ 0.145 $ 0.145 $ 0.145 $ 0.145 2014 $ 0.140 $ 0.140 $ 0.140 $ 0.120 On January 18, 2017 , NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, or $0.12 per share on an annualized basis, payable on February 15, 2017 , to stockholders of record as of February 1, 2017 . 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 the lesser of 85% of its fair market value on the offering date or 85% of the fair market value on the exercise date. An offering date occurs each January 1 and July 1. An exercise date occurs each June 30 and December 31. As of December 31, 2016 , there remained 667,819 shares of treasury stock reserved for issuance under the ESPP, and in the first quarter of 2017 , 282,530 shares of common stock were issued to employee accounts from treasury stock. Share Repurchases — During 2015 and 2014, the Company's board of directors authorized share repurchases of $481 million of its common stock, which were made as follows: Total number of shares purchased Average price paid per share (a) Amounts paid for shares purchased (in millions) (a) Board Authorized Share Repurchases Fourth Quarter 2014 1,624,360 $ 26.95 $ 44 First Quarter 2015 3,146,484 25.15 79 Second Quarter 2015 4,379,907 24.53 107 Third Quarter 2015 11,104,184 15.06 167 Fourth Quarter 2015 5,558,920 15.03 84 Total Board Authorized Share Repurchases 25,813,855 $ 481 (a) The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.015 per share paid in connection with the share repurchase. Preferred Stock 2.822% Redeemable Preferred Stock Preferred Stock On December 23, 2014, NRG and the Credit Suisse Group amended and restated its 250,000 shares of 3.625% Convertible Perpetual Preferred Stock, or 3.625% Preferred Stock, which is treated as redeemable preferred stock, initially issued on August 11, 2005, to the Credit Suisse Group in a private placement. The amendment resulted in a reduction of the rate from 3.625% to 2.822% and is hereby referred to as the 2.822% Preferred Stock. The transaction was accounted for as an extinguishment of the 3.625% Preferred Stock and the issuance of new 2.822% Preferred Stock. The loss on extinguishment of the 3.625% Preferred Stock of $42 million represents the increase in redeemable preferred stock as the Company recorded the 2.822% Preferred Stock at a fair value of $291 million in connection with the amendment. The loss on extinguishment of $42 million as well as $5 million in consent fees paid to Credit Suisse, were recorded as a dividend on the preferred shares. This amount reduced net income to arrive at net income/(loss) available to NRG common stockholders in the calculation of earnings per share for the year ended December 31, 2014. On May 24, 2016, NRG entered an agreement with Credit Suisse Group to repurchase 100% of the outstanding shares of its $344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares at a price of $226 million . The transaction resulted in a gain on redemption of $78 million , measured as the difference between the fair value of the cash consideration paid upon redemption of $226 million and the carrying value of the preferred stock at the time of the redemption of $304 million . This amount is reflected in net income/(loss) available to NRG common stockholders in the calculation of earnings per share. The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended December 31, 2016 , 2015 , and 2014: (In millions) Balance as of December 31, 2013 $ 249 Loss recorded in connection with extinguishment of 3.625% preferred stock and issuance of 2.822% preferred stock 42 Balance as of December 31, 2014 291 Accretion to redemption value 11 Balance as of December 31, 2015 302 Accretion to redemption value 2 Repurchase of 2.822% redeemable preferred stock (226 ) Gain on redemption of 2.822% redeemable preferred stock (78 ) Balance as of December 31, 2016 $ —

Investments Accounted for by th

Investments Accounted for by the Equity Method and Variable Interest Entities (Notes)	12 Months Ended
	Dec. 31, 2016
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 Entities that are not Consolidated 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, 2016 : Name Economic Interest Investment Balance (In millions) Avenal Solar Holdings LLC (a) 50.0 % $ (7 ) Community Wind North, LLC 99.0 % 21 Desert Sunlight Investment Holdings, LLC (a) 25.0 % 282 Elkhorn Ridge Wind, LLC (a) 47.0 % 85 GenConn Energy LLC (a) 50.0 % 106 Four Brothers Holdings (c) 50.0 % 208 Granite Mountain Renewables (c) 50.0 % 90 Iron Springs Renewables (c) 50.0 % 48 Midway-Sunset Cogeneration Company 50.0 % 22 Petra Nova Parish Holdings LLC 50.0 % 34 Saguaro Power Company 50.0 % (14 ) San Juan Mesa Wind Project, LLC (a) 75.0 % 74 Sherbino I Wind Farm LLC 50.0 % — Watson Cogeneration Company 49.0 % 26 Gladstone Power Station (b) 37.5 % 132 Other Various 13 Total equity investments in affiliates $ 1,120 (a) Equity method investments owned by NRG Yield (b) Gladstone Power Station is located in Australia (c) Economic interest based on cash to be distributed As of December 31, 2016 2015 (In millions) Undistributed earnings from equity investments $ 101 $ 55 Utility-Scale Solar Portfolio — As described in Note 3 , Business Acquisitions and Dispositions , on November 2, 2016, the Company acquired equity interests in a tax equity portfolio, located in Utah, comprised of 530 MW of mechanically-complete solar assets. These equity interests in Four Brothers Holdings, Granite Mountain Renewables, and Iron Springs Renewables are accounted for as equity method investments. Variable Interest Entities NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, for which NRG is not the primary beneficiary, under the equity method. GenConn — NRG owns a 50% interest in GenConn, a limited liability company formed to construct, own and operate two 190 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. GenConn has 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% . As of December 31, 2016 , $212 million was outstanding under the note and $14 million was drawn on the working capital facility. The note is secured by all of the GenConn assets. NRG's maximum exposure to loss is limited to its equity investment, which was $106 million as of December 31, 2016 . Sherbino — 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, 2016 , the outstanding principal balance of the term loan facility was $72 million , and is secured by substantially all of Sherbino's assets and membership interests. During the fourth quarter of 2016, the Company recorded an other-than-temporary impairment loss equal to the full value of its investment in Sherbino of $70 million as further described in Note 10 , Asset Impairments . Other Equity Investments Gladstone — Through a joint venture, NRG owns a 37.5% interest in Gladstone, a 1,613 MW 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. NRG's investment in Gladstone was $132 million as of December 31, 2016 . Entities that are Consolidated The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits as further described in Note 2 , Summary of Significant Accounting Policies . For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $88 million as of December 31, 2016 , which would be required to be funded if the arrangement were to be dissolved. The summarized financial information for the Company's consolidated VIEs consisted of the following: (In millions) December 31, 2016 December 31, 2015 Current assets $ 87 $ 84 Net property, plant and equipment 1,534 1,807 Other long-term assets 954 863 Total assets 2,575 2,754 Current liabilities 59 56 Long-term debt 442 366 Other long-term liabilities 183 179 Total liabilities 684 601 Noncontrolling interests 529 493 Net assets less noncontrolling interests $ 1,362 $ 1,660

Segment Reporting (Notes)

Segment Reporting (Notes)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting The Company's segment structure reflects how management currently makes financial decisions and allocates resources. During January 2017, the Company's businesses are segregated as follows: Generation, which includes generation, international and BETM (previously part of Corporate); Retail which includes Mass customers (previously Retail Mass), and Business Solutions, which includes C&I customers and other distributed and reliability products (previously in the Generation segment); Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. The Company's corporate segment includes residential solar and electric vehicle services. Intersegment sales are accounted for at market. The financial information for years ended December 31, 2016 , 2015 , and 2014 have been recast to reflect these changes. NRG Yield includes certain of the Company's contracted generation assets. On September 1, 2016 NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. This acquisition was accounted for as transfers of entities under common control and accordingly, all historical periods have been recast to reflect this change. NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss) and net income/(loss) attributable to NRG Energy, Inc. During the years ended December 31, 2016 , 2015 and 2014 , the Company had one customer in the East region within Generation which comprised more than 10% of the Company's consolidated revenues. For the Year Ended December 31, 2016 Generation (a) Retail (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 5,679 $ 6,336 $ 417 $ 1,021 $ 77 $ (1,179 ) $ 12,351 Operating expenses 4,922 5,169 215 322 212 (1,184 ) 9,656 Depreciation and amortization 702 115 190 297 63 — 1,367 Impairment losses 645 1 56 183 33 — 918 Acquisition-related transaction and integration costs — — — 1 7 — 8 Development costs 22 4 40 — 24 — 90 Total operating cost and expenses 6,291 5,289 501 803 339 (1,184 ) 12,039 Gain/(loss) on sale of assets 294 (1 ) — — (78 ) — 215 Operating (loss)/income (318 ) 1,046 (84 ) 218 (340 ) 5 527 Equity in (losses)/earnings of unconsolidated affiliates (5 ) — (30 ) 37 7 18 27 Impairment losses on investments (142 ) — (105 ) — (21 ) — (268 ) Other income, net 36 1 1 3 62 (61 ) 42 Loss on debt extinguishment — — — — (142 ) — (142 ) Interest expense (79 ) (1 ) (108 ) (274 ) (658 ) 59 (1,061 ) (Loss)/income before income taxes (508 ) 1,046 (326 ) (16 ) (1,092 ) 21 (875 ) Income tax (benefit)/expense (1 ) 1 (20 ) (1 ) 37 — 16 Net (loss)/income $ (507 ) $ 1,045 $ (306 ) $ (15 ) $ (1,129 ) $ 21 $ (891 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — — (13 ) (54 ) 16 (66 ) (117 ) Net (loss)/income attributable to NRG Energy, Inc. $ (507 ) $ 1,045 $ (293 ) $ 39 $ (1,145 ) $ 87 $ (774 ) Balance sheet Equity investments in affiliates $ 204 $ — $ 372 $ 710 $ 91 $ (257 ) $ 1,120 Capital expenditures (b) 767 12 330 23 110 — 1,242 Goodwill 199 340 12 111 662 Total assets $ 13,256 $ 1,977 $ 5,280 $ 8,383 $ 15,590 $ (14,131 ) $ 30,355 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 955 $ 4 $ 23 $ 8 $ 189 $ — $ 1,179 (b) Includes accruals. For the Year Ended December 31, 2015 Generation (a) Retail (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 7,546 $ 6,914 $ 392 $ 953 $ 39 $ (1,170 ) $ 14,674 Operating expenses 6,210 6,113 185 333 291 (1,149 ) 11,983 Depreciation and amortization 896 133 181 297 59 — 1,566 Impairment losses 4,827 36 13 — 132 22 5,030 Acquisition-related transaction and integration costs — 1 — 3 6 — 10 Development costs 27 4 52 — 63 — 146 Total operating cost and expenses 11,960 6,287 431 633 551 (1,127 ) 18,735 Gain on postretirement benefits curtailment 21 — — — — — 21 Operating (loss)/income (4,393 ) 627 (39 ) 320 (512 ) (43 ) (4,040 ) Equity in earnings/(losses) of unconsolidated affiliates 10 — 9 26 — (9 ) 36 Impairment losses on investments (14 ) — — — (42 ) — (56 ) Other income, net 48 (1 ) 3 3 78 (98 ) 33 (Loss)/gain on debt extinguishment — — — (9 ) 84 — 75 Loss on sale of equity method investment — — — — (14 ) — (14 ) Interest expense (97 ) (1 ) (83 ) (263 ) (779 ) 95 (1,128 ) (Loss)/income before income taxes (4,446 ) 625 (110 ) 77 (1,185 ) (55 ) (5,094 ) Income tax expense/(benefit) — 1 (18 ) 12 1,347 — 1,342 Net (loss)/income (4,446 ) 624 (92 ) 65 (2,532 ) (55 ) (6,436 ) Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests — — 6 19 (37 ) (42 ) (54 ) Net (loss)/income attributable to NRG Energy, Inc. $ (4,446 ) $ 624 $ (98 ) $ 46 $ (2,495 ) $ (13 ) $ (6,382 ) Balance sheet Equity investments in affiliates $ 334 $ — $ 134 $ 697 $ 127 $ (247 ) $ 1,045 Capital expenditures (b) 792 36 163 30 246 — 1,267 Goodwill 536 340 12 — 111 — 999 Total assets $ 17,625 $ 2,017 $ 5,142 $ 8,689 $ 19,720 $ (20,311 ) $ 32,882 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 898 $ 6 $ 25 $ 29 $ 212 $ — $ 1,170 (b) Includes accruals. For the Year Ended December 31, 2014 Generation (a) Retail (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 9,288 $ 7,393 $ 344 $ 828 $ 19 $ (2,004 ) $ 15,868 Operating expenses 6,985 7,270 191 285 151 (2,058 ) 12,824 Depreciation and amortization 957 134 164 233 35 — 1,523 Impairment losses 87 — 32 — (22 ) — 97 Acquisition-related transaction and integration costs 1 3 — 4 76 — 84 Development costs 12 1 40 — 35 — 88 Total operating costs and expenses 8,042 7,408 427 522 275 (2,058 ) 14,616 Gain on sale of assets 19 — — — — — 19 Operating income/(loss) 1,265 (15 ) (83 ) 306 (256 ) 54 1,271 Equity in earnings/(losses)of unconsolidated affiliates 23 — (4 ) 17 — 2 38 Other income, net 39 — 1 6 75 (99 ) 22 Gain on sale of equity method investment 18 — — — — — 18 Loss on debt extinguishment — — (1 ) (1 ) (93 ) — (95 ) Interest expense (94 ) (2 ) (97 ) (216 ) (806 ) 96 (1,119 ) Income/(loss) before income taxes 1,251 (17 ) (184 ) 112 (1,080 ) 53 135 Income tax expense/(benefit) 3 1 — 4 (5 ) — 3 Net income/(loss) $ 1,248 (18 ) (184 ) 108 (1,075 ) 53 132 Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (1 ) — 2 16 5 (24 ) (2 ) Net income/(loss) attributable to NRG Energy, Inc. $ 1,249 $ (18 ) $ (186 ) $ 92 $ (1,080 ) $ 77 $ 134 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 1,873 $ 7 $ 25 $ 12 $ 85 $ — $ 2,002 As of December 31, 2016, the Company's businesses were segregated as follows: Generation (previously named Generation/Business), which includes generation, international and business solutions; Retail Mass (previously NRG Home Retail); Renewables (previously named NRG Renew), which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. The Company's corporate segment included BETM, residential solar (previously part of NRG Home) and electric vehicle services. During 2016, the Company began reporting the results of its residential solar business in its corporate segment and its international business in its Generation segment. The financial information for years ended December 31, 2016 , 2015 , and 2014 have been recast to reflect these changes. NRG Yield includes certain of the Company's contracted generation assets. On September 1, 2016 NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. This acquisition was accounted for as transfers of entities under common control and accordingly, all historical periods have been recast to reflect this change. For the Year Ended December 31, 2016 Generation (a) Retail Mass (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 6,927 $ 4,966 $ 417 $ 1,021 $ 137 $ (1,117 ) $ 12,351 Operating expenses 6,020 3,987 215 322 235 (1,123 ) 9,656 Depreciation and amortization 712 104 190 297 64 — 1,367 Impairment losses 646 — 56 183 33 — 918 Acquisition-related transaction and integration costs — — — 1 7 — 8 Development costs 26 — 40 — 24 — 90 Total operating cost and expenses 7,404 4,091 501 803 363 (1,123 ) 12,039 Gain/(loss) on sale of assets 293 — — — (78 ) — 215 Operating (loss)/income (184 ) 875 (84 ) 218 (304 ) 6 527 Equity in (losses)/earnings of unconsolidated affiliates (5 ) — (30 ) 37 7 18 27 Impairment losses on investments (142 ) — (105 ) — (21 ) — (268 ) Other income, net 37 — 1 3 62 (61 ) 42 Loss on debt extinguishment — — — — (142 ) — (142 ) Interest expense (80 ) — (108 ) (274 ) (658 ) 59 (1,061 ) (Loss)/income before income taxes (374 ) 875 (326 ) (16 ) (1,056 ) 22 (875 ) Income tax (benefit)/expense — — (20 ) (1 ) 37 — 16 Net (loss)/income $ (374 ) $ 875 $ (306 ) $ (15 ) $ (1,093 ) $ 22 $ (891 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — — (13 ) (54 ) 16 (66 ) (117 ) Net (loss)/income attributable to NRG Energy, Inc. $ (374 ) $ 875 $ (293 ) $ 39 $ (1,109 ) $ 88 $ (774 ) Balance sheet Equity investments in affiliates $ 204 $ — $ 372 $ 710 $ 91 $ (257 ) $ 1,120 Capital expenditures (b) 779 59 330 23 51 — 1,242 Goodwill 199 340 12 — 111 — 662 Total assets $ 13,234 $ 1,589 $ 5,280 $ 8,383 $ 15,734 $ (13,865 ) $ 30,355 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 893 $ 2 $ 23 $ 8 $ 191 $ — $ 1,117 (b) Includes accruals. For the Year Ended December 31, 2015 Generation (a) Retail Mass (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 9,097 $ 5,389 $ 392 $ 953 $ 14 $ (1,171 ) $ 14,674 Operating expenses 7,744 4,561 184 333 310 (1,149 ) 11,983 Depreciation and amortization 907 123 180 297 59 — 1,566 Impairment losses 4,827 36 13 — 132 22 5,030 Acquisition-related transaction and integration costs — 1 — 3 6 — 10 Development costs 31 — 52 — 63 — 146 Total operating cost and expenses 13,509 4,721 429 633 570 (1,127 ) 18,735 Gain on postretirement benefits curtailment 21 — — — — — 21 Operating (loss)/income (4,391 ) 668 (37 ) 320 (556 ) (44 ) (4,040 ) Equity in earnings/(losses) of unconsolidated affiliates 10 — 9 26 (3 ) (6 ) 36 Impairment losses on investments (14 ) — — — (42 ) — (56 ) Other income, net 48 — 3 3 77 (98 ) 33 (Loss)/gain on debt extinguishment — — — (9 ) 84 — 75 Loss on sale of equity method investment — — — — (14 ) — (14 ) Interest expense (98 ) — (83 ) (263 ) (779 ) 95 (1,128 ) (Loss)/income before income taxes (4,445 ) 668 (108 ) 77 (1,233 ) (53 ) (5,094 ) Income tax expense/(benefit) 1 — (18 ) 12 1,347 — 1,342 Net (loss)/income (4,446 ) 668 (90 ) 65 (2,580 ) (53 ) (6,436 ) Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests — — 6 19 (37 ) (42 ) (54 ) Net (loss)/income attributable to NRG Energy, Inc. $ (4,446 ) $ 668 $ (96 ) $ 46 $ (2,543 ) $ (11 ) $ (6,382 ) Balance sheet Equity investments in affiliates $ 334 $ — $ 134 $ 697 $ 127 $ (247 ) $ 1,045 Capital expenditures (b) 798 30 163 30 246 — 1,267 Goodwill 536 340 12 — 111 — 999 Total assets $ 17,324 $ 1,876 $ 5,142 $ 8,689 $ 19,926 $ (20,075 ) $ 32,882 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 898 $ 6 $ 25 $ 29 $ 213 $ — $ 1,171 (b) Includes accruals. For the Year Ended December 31, 2014 Generation (a) Retail Mass (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 11,113 $ 5,503 $ 344 $ 828 $ 82 $ (2,002 ) $ 15,868 Operating expenses 8,993 5,236 191 285 171 (2,052 ) 12,824 Depreciation and amortization 966 122 164 233 38 — 1,523 Impairment losses 87 — 32 — (22 ) — 97 Acquisition-related transaction and integration costs 1 3 — 4 76 — 84 Development costs 13 — 40 — 35 — 88 Total operating costs and expenses 10,060 5,361 427 522 298 (2,052 ) 14,616 Gain on sale of assets 19 — — — — — 19 Operating income/(loss) 1,072 142 (83 ) 306 (216 ) 50 1,271 Equity in earnings/(losses)of unconsolidated affiliates 23 — (4 ) 17 — 2 38 Other income, net 39 — 1 6 75 (99 ) 22 Gain on sale of equity method investment 18 — — — — — 18 Loss on debt extinguishment — — (1 ) (1 ) (93 ) — (95 ) Interest expense (95 ) (1 ) (97 ) (216 ) (806 ) 96 (1,119 ) Income/(loss) before income taxes 1,057 141 (184 ) 112 (1,040 ) 49 135 Income tax expense/(benefit) 4 — — 4 (5 ) — 3 Net income/(loss) 1,053 141 (184 ) 108 (1,035 ) 49 132 Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (1 ) — 2 16 5 (24 ) (2 ) Net income/(loss) attributable to NRG Energy, Inc. $ 1,054 $ 141 $ (186 ) $ 92 $ (1,040 ) $ 73 $ 134 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 1,873 $ 7 $ 25 $ 12 $ 85 $ — $ 2,002

Earnings Per Share (Notes)

Earnings Per Share (Notes)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Share	Earnings/(Loss) Per Share Basic earnings/(loss) per common share is computed by dividing net income/(loss) 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 earnings/(loss) per share is computed in a manner consistent with that of basic earnings/(loss) 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, and market stock units are not considered outstanding for purposes of computing basic earnings/(loss) per share. However, these instruments are included in the denominator for purposes of computing diluted earnings/(loss) per share under the treasury stock method. The if-converted method was used to determine the dilutive effect of embedded derivatives in the Company's 2.822% Preferred Stock for the years ended December 31, 2015 and 2014. During 2016, the Company repurchased 100% of the outstanding shares of its 2.822% preferred stock. The reconciliation of NRG's basic earnings/(loss) per share to diluted earnings/(loss) per share is shown in the following table: Year Ended December 31, 2016 2015 2014 (In millions, except per share amounts) Basic (loss)/earnings per share attributable to NRG common stockholders Net (loss)/income attributable to NRG Energy, Inc. $ (774 ) $ (6,382 ) $ 134 Dividends for preferred shares 5 20 9 Dividends for refinancing of preferred shares — — 47 Gain on redemption of 2.822% redeemable perpetual preferred shares (78 ) — — (Loss)/Income Available to Common Stockholders $ (701 ) $ (6,402 ) $ 78 Weighted average number of common shares outstanding 316 329 334 (Loss)/Earnings per weighted average common share — basic $ (2.22 ) $ (19.46 ) $ 0.23 Diluted (loss)/earnings per share attributable to NRG common stockholders Weighted average number of common shares outstanding 316 329 334 Incremental shares attributable to the issuance of equity compensation (treasury stock method) — — 5 Total dilutive shares 316 329 339 (Loss)/Earnings per weighted average common share — diluted $ (2.22 ) $ (19.46 ) $ 0.23 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 earnings/(loss) per share: Year Ended December 31, 2016 2015 2014 (In millions of shares) Equity compensation 5 6 1 Embedded derivative of 2.822% redeemable perpetual preferred stock — 16 16 Total 5 22 17

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The income tax provision from continuing operations consisted of the following amounts: Year Ended December 31, 2016 2015 2014 (In millions, except percentages) Current State $ 17 $ 6 $ 8 Total — current 17 6 8 Deferred U.S. Federal 3 1,020 (50 ) State (6 ) 315 41 Foreign 2 1 4 Total — deferred (1 ) 1,336 (5 ) Total income tax expense $ 16 $ 1,342 $ 3 Effective tax rate (1.8 )% (26.3 )% 2.2 % The following represents the domestic and foreign components of income/(loss) before income tax expense/(benefit): Year Ended December 31, 2016 2015 2014 (In millions) U.S. $ (886 ) $ (5,105 ) $ 126 Foreign 11 11 9 Total $ (875 ) $ (5,094 ) $ 135 A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate is as follows: Year Ended December 31, 2016 2015 2014 (In millions, except percentages) (Loss)/income before income taxes $ (875 ) $ (5,094 ) $ 135 Tax at 35% (306 ) (1,783 ) 47 State taxes 11 (218 ) 9 Foreign operations 10 1 1 Federal and state tax credits, excluding PTCs — (5 ) (1 ) Valuation allowance 306 3,039 6 Impact of non-taxable equity earnings 22 (10 ) (11 ) Book goodwill impairment — 340 — Net interest accrued on uncertain tax positions 1 (3 ) (2 ) Production tax credit (26 ) (33 ) (48 ) Recognition of uncertain tax benefits 2 (15 ) (30 ) Tax expense attributable to consolidated partnerships (1 ) 12 4 Impact of change in effective state tax rate 1 19 22 Other (4 ) (2 ) 6 Income tax expense $ 16 $ 1,342 $ 3 Effective income tax rate (1.8 )% (26.3 )% 2.2 % For the year ended December 31, 2016 , NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the change in valuation allowance, the impact of non-taxable equity earnings and current state tax expense, partially offset by the generation of PTCs from various wind facilities. For the year ended December 31, 2015 , NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to recording of a valuation allowance on the federal and certain state net deferred tax assets that may not be realizable under a “more likely than not” measurement. In addition, a portion of the book goodwill impairment is classified as a permanent reversal impacting the effective tax rate. For the year ended December 31, 2014 , NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of PTCs generated from various wind facilities including assets acquired in the EME transaction, and a benefit resulting from the recognition of uncertain tax benefits, partially offset by state and local income taxes including a change in the effective state rate. The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following: As of December 31, 2016 2015 (In millions) Deferred tax liabilities: Emissions allowances $ 30 $ 31 Derivatives, net — 22 Cumulative translation adjustments 11 2 Investment in projects 374 838 Total deferred tax liabilities 415 893 Deferred tax assets: Deferred compensation, accrued vacation and other reserves 318 255 Discount/premium on notes 45 68 Difference between book and tax basis of property 1,511 1,210 Goodwill 83 39 Differences between book and tax basis of contracts 301 516 Pension and other postretirement benefits 183 218 Equity compensation 11 50 Bad debt reserve 12 6 U.S. capital loss carryforwards 1 1 U.S. Federal net operating loss carryforwards 1,171 1,373 Foreign net operating loss carryforwards 63 59 State net operating loss carryforwards 223 230 Foreign capital loss carryforwards 1 1 Deferred financing costs 4 6 Federal and state tax credit carryforwards 446 439 Federal benefit on state uncertain tax positions 12 17 Intangibles amortization (excluding goodwill) 211 90 Derivatives, net 101 — Inventory obsolescence 31 27 Other 8 11 Total deferred tax assets 4,736 4,616 Valuation allowance (4,116 ) (3,575 ) Total deferred tax assets, net of valuation allowance 620 1,041 Net deferred tax asset $ 205 $ 148 The following table summarizes NRG's net deferred tax position: As of December 31, 2016 2015 (In millions) Net deferred tax asset — noncurrent $ 225 $ 167 Net deferred tax liability — noncurrent (20 ) (19 ) Net deferred tax asset $ 205 $ 148 Deferred tax assets and valuation allowance Net deferred tax balance — As of December 31, 2016 and 2015 , NRG recorded a net deferred tax asset of $4.3 billion and $3.7 billion , respectively. The Company believes the federal and certain state net deferred tax assets may not be realizable under a “more likely than not” measurement and as such, a valuation allowance has been recorded to reduce the asset accordingly. The Company assesses cumulative and forecasted pretax book earnings and the future reversal of existing taxable temporary differences. Based on the Company's 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 $4.1 billion and $3.6 billion of tax assets as of December 31, 2016 , and 2015 , respectively, thus a valuation allowance has been recorded. The net deferred tax asset of $205 million is predominantly due to the inclusion of NRG Yield Inc.'s net deferred tax asset consisting primarily of net operating losses. NOL carryforwards — At December 31, 2016 , the Company had tax effected cumulative domestic NOLs consisting of carryforwards for federal income tax purposes of $1.2 billion and state of $223 million . The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before expiration commencing in 2026. In addition, NRG has cumulative foreign NOL carryforwards of $63 million with no expiration date. Valuation allowance — As of December 31, 2016 , the Company's tax effected valuation allowance was $4.1 billion , consisting of domestic federal net deferred tax assets of approximately $3.6 billion , domestic state net deferred tax assets of $504 million , foreign net operating loss carryforwards of $63 million and foreign capital loss carryforwards of approximately $1 million . Based upon the assessment of cumulative and forecasted pretax book earnings, and the future reversal of existing taxable temporary differences, it was determined that a valuation allowance was required to be recorded during the year. Taxes Receivable and Payable As of December 31, 2016 , NRG recorded a current tax payable of $8 million that represents a tax liability due for state income taxes. NRG has a tax receivable of $29 million , comprised of, $10 million due from the New York State Empire Zone program, and $11 million of refunds due from state income tax estimated payments and return filings for 2016 and 2015, respectively. The remaining balance of $8 million relates to federal cash grants applied for eligible solar energy projects, net of sequestration. Uncertain tax benefits NRG has identified uncertain tax benefits whose after-tax value is $34 million for which, as of December 31, 2016, and 2015, NRG has recorded a non-current tax liability of $37 million and $35 million , respectively. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the year ended December 31, 2016 , the Company recognized an expense of $1 million in interest. As of December 31, 2016 and 2015 , NRG had cumulative interest and penalties related to these uncertain tax benefits of $4 million and $3 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. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 2010. The following table reconciles the total amounts of uncertain tax benefits: As of December 31, 2016 2015 (In millions) Balance as of January 1 $ 32 $ 71 Increase due to current year positions 8 4 Decrease due to prior year positions — (25 ) Decrease due to settlements and payments (6 ) (18 ) Uncertain tax benefits as of December 31 $ 34 $ 32

Stock-Based Compensation (Notes

Stock-Based Compensation (Notes)	12 Months Ended
	Dec. 31, 2016
Share-based Compensation [Abstract]
Stock-Based Compensation	Stock-Based Compensation NRG Energy, Inc. Long-Term Incentive Plan As of December 31, 2016 and 2015 , a total of 22,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP, and 5,558,390 shares of NRG common stock were authorized for issuance under the NRG GenOn LTIP. The NRG LTIP and the NRG GenOn LTIP are 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 7,487,058 and 6,240,648 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 2016 and 2015 , respectively. There were 960,904 and 1,671,633 shares of common stock remaining available for grants under the NRG GenOn LTIP as of December 31, 2016 and 2015 , respectively. 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 10 years for NRG's outstanding NQSOs. No NQSOs were granted in 2016, 2015 or 2014. The following table summarizes the Company's NQSO activity and changes during the year: Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (In years) (In millions) Outstanding at December 31, 2015 2,071,913 $ 32.27 3 $ — Forfeited (548,994 ) 52.34 Outstanding at December 31, 2016 1,522,919 25.03 3 — Exercisable at December 31, 2016 1,522,919 25.03 3 — The following table summarizes the total intrinsic value of options exercised and the cash received from the exercises of options: Year Ended December 31, 2016 2015 2014 (In millions) Total intrinsic value of options exercised $ — $ 2 $ 7 Cash received from options exercised — 9 21 There were no options that exercised during the year ended December 31, 2016. Restricted Stock Units As of December 31, 2016 , RSUs granted under the Company's LTIPs typically have three -year graded vesting schedules beginning on the grant date. 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 Non-vested at December 31, 2015 2,261,996 $ 27.59 Granted 1,226,957 11.54 Forfeited (592,163 ) 22.91 Vested (916,649 ) 26.07 Non-vested at December 31, 2016 1,980,141 19.29 The total fair value of RSUs vested during the years ended December 31, 2016 , 2015 , and 2014 , was $11 million , $10 million and $26 million , respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2016 , 2015 , and 2014 was $11.54 , $27.31 , and $29.90 , 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 Outstanding at December 31, 2015 427,578 $ 21.88 Granted 102,147 16.85 Converted to Common Stock (76,051 ) 18.37 Outstanding at December 31, 2016 453,674 21.54 The aggregate intrinsic values for DSUs outstanding as of December 31, 2016 , 2015 , and 2014 were approximately $6 million , $5 million , and $10 million respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2016 , 2015 , and 2014 were $1 million , less than a million , and $1 million , respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2016 , 2015 , and 2014 was $16.85 , $25.14 and $35.63 , 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 the performance period, typically 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) three quarters of one share of common stock if the TSR has decreased by no more than 25% over the performance period; (ii) one share of common stock, if there is no change in TSR over the performance period; and (iii) two shares of common stock if the TSR increases 100% or more over the performance period. If there is more than a 25% reduction in TSR over the performance period, no common stock will be paid. If the TSR is between 75% and 100% over the performance period, shares awarded are interpolated. The value of the common stock on the date of grant is based on the closing price of NRG common stock on the date of grant. 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 Non-vested at December 31, 2015 1,980,157 $ 29.54 Granted 806,409 14.73 Forfeited (1,499,963 ) 27.76 Vested (4,015 ) 33.81 Non-vested at December 31, 2016 1,282,588 21.47 The weighted average grant date fair value of MSUs granted during the years ended December 31, 2016 , 2015 and 2014 , was $14.73 , $26.68 and $31.90 , 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: 2016 2015 Expected volatility 34.33 % 24.08%-25.20% Expected term (in years) 3 1-3 Risk free rate 1.31 % 0.25%-1.07% For the years ended December 31, 2016 and 2015 , 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. 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, 2016 for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $5 million , $21 million , and $16 million for the years ended December 31, 2016 , 2015 , and 2014 , 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 Total Cost Weighted Average Recognition Period Remaining (In years) Year Ended December 31 As of December 31 Award 2016 2015 2014 2016 2016 (In millions, except weighted average data) NQSOs (a) $ — $ — $ 1 $ — — RSUs 14 23 20 12 1.46 DSUs 2 2 2 — — MSUs 3 16 19 7 1.54 PRSUs (b) 5 — — 8 1.30 Total $ 24 $ 41 $ 42 $ 27 Tax detriment recognized $ (4 ) $ (12 ) $ (8 ) (a) All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2016 and 2015. (b) Phantom Restricted Stock Units, PRSUs, are liability-classified time-based awards that typically vest ratably over a three -year period. The amount to be paid upon vesting is based on NRG's closing stock price for the period.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions The following table summarizes NRG's material related party transactions with third party affiliates that are included in the Company's operating revenues, operating costs and other income and expense: Year Ended December 31, 2016 2015 2014 (In millions) Revenues from Related Parties Included in Operating Revenues Gladstone $ 2 $ 4 $ 6 GenConn 5 4 6 Total $ 7 $ 8 $ 12 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 provides services to GenConn under operations and maintenance agreements with GenConn Devon and GenConn Middletown that began in June 2011. Keystone and Conemaugh facilities — The Company operates the Keystone and Conemaugh facilities under five-year agreements that initially expired in December 2015 and were renewed through December 2020 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 $11 million in 2016 , $11 million in 2015 , and $10 million in 2014 .

Commitments and Contingencies (

Commitments and Contingencies (Notes)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Operating Lease Commitments Powerton and Joliet Leases The Company leases 100% interests in the Powerton facility and Unit 7 and Unit 8 of the Joliet facility through 2034 and 2030 , respectively, through its indirect subsidiary, Midwest Generation, 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 EME, the Company recorded the out-of-market value as a liability in out-of-market contracts of $159 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 $14 million per year through the term of the lease. Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31, 2016 , are as follows: Period (In millions) 2017 $ 1 2018 1 2019 1 2020 1 2021 3 Thereafter 234 Total $ 241 GenOn Mid-Atlantic Leases The Company leases 100% interests 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. 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 is being 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 $43 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, 2016 are as follows: Period (In millions) 2017 $ 144 2018 105 2019 139 2020 105 2021 42 Thereafter 400 Total $ 935 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% interests in the Conemaugh and Keystone coal generation facilities through 2034, and expects to make payments under the leases through 2029 in accordance with the terms of the leases. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. 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 is being 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 $29 million per year through the term of the lease. Future minimum lease commitments under the REMA operating leases for the years ending after December 31, 2016 are as follows: Period (In millions) 2017 $ 63 2018 55 2019 65 2020 56 2021 47 Thereafter 231 Total $ 517 Other Operating Leases NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2050. NRG also has certain tolling arrangements to purchase power, which qualify as operating leases. Certain operating lease agreements include provisions such as scheduled rent increases, leasehold incentives, and rent concessions over their lease term. 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 $102 million , $100 million , and $106 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Future minimum lease commitments under operating leases for the years ending after December 31, 2016 are as follows: Period (In millions) 2017 $ 84 2018 76 2019 67 2020 61 2021 52 Thereafter 443 Total (a) $ 783 (a) Amounts in the table exclude future sublease income of $14 million associated with long-term leases for office locations. 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, 2016 , 2015 , and 2014 , the Company purchased $1.8 billion , $2.6 billion , and $3.5 billion , respectively, under such arrangements. As of December 31, 2016 , the Company's commitments under such outstanding agreements are as follows: Period (In millions) 2017 $ 638 2018 251 2019 174 2020 140 2021 109 Thereafter 415 Total $ 1,727 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, 2016 . Minimum purchase commitment obligations are as follows as of December 31, 2016 : Period (In millions) 2017 $ 25 2018 17 2019 13 2020 11 2021 21 Thereafter — Total (a) $ 87 (a) As of December 31, 2016 , the maximum remaining term under any individual purchased power contract is five years. Lignite Contract with Texas Westmoreland Coal Co. The Company's Limestone facility utilizes a blend of coal including lignite 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 a cost-plus arrangement with certain performance incentives and penalties. On August 18, 2016, NRG gave notice to TWCC terminating the active mining of lignite under the contract, effective on December 31, 2016. Under the contract, TWCC continues to be responsible for reclamation activities. NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of $95.5 million on TWCC for the reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety bonds. Additionally, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas. First Lien Structure NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing, 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, 2016 , hedges under the first lien were out-of-the-money for NRG on a counterparty aggregate basis. Nuclear Insurance STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Act. Effective January 1, 2017, the current liability limit per incident is $13.44 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 next due no later than September 10, 2018. Under the Price-Anderson Act, owners of nuclear power plants in the U.S. are required to purchase primary insurance limits of $450 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 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 approximately $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 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 $1.25 billion in limits (excess of the first $1.5 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 a NEIL companion policy provides Accidental Outage coverage for the co-owners of STP's lost revenue following a property damage event, at a weekly indemnity limit of $2.52 million per unit up to a maximum of $274.4 million nuclear and $183.5 million non-nuclear, and is subject to an eight-week waiting period. NRG also purchases 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 6 years after the policy expires. Ivanpah Energy Production Guarantee The Company's PPAs with PG&E with respect to the Ivanpah plant contain provisions for contract quantity and guaranteed energy production, which require that Ivanpah units 1 and 3 deliver to PG&E no less than the guaranteed energy production amount specified in the PPAs in any period of twenty-four consecutive months, or performance measurement period, during the term of the PPAs. In January 2017, the Company and PG&E executed amendments to the PPAs that provide, among other things, the ability to cure any failure to meet the guaranteed energy production amounts through performance and liquidated damage provisions. On February 2, 2017, PG&E filed a request with the CPUC to approve the amendments. Pending final and nonappealable CPUC approval, PG&E agreed to refrain from declaring any event of default with respect to any failure to deliver the guaranteed energy production amounts. 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. As applicable, the Company has established an adequate reserve for the matters discussed below. 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. Midwest Generation Asbestos Liabilities — The Company, through its subsidiary, Midwest Generation, may be subject to potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzing the scope of potential liability as it may relate to Midwest Generation. The Company believes that it has established an adequate reserve for these cases. 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 Mirant's 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, or the Fifth Circuit. In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. The appeal has been fully briefed by the parties and was argued before the Fifth Circuit on February 8, 2017. 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 state antitrust law 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 was 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 which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Court of Appeals' decision and the Supreme Court granted the petition. On April 21, 2015, the Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution. The Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings. On March 7, 2016, class plaintiffs filed their motions for class certification. Defendants filed their briefs in opposition to class plaintiffs' motions for class certification on June 24, 2016. On January 26, 2017, the court heard oral argument on several motions, including plaintiffs' motion on class certification. In May 2016, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment in one of the Kansas cases. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits. In September 2012, the State of Nevada Supreme Court, which was 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 a writ of certiorari to the U.S. Supreme Court. In June 2013, the Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits. Energy Plus Holdings — On August 7, 2012, Energy Plus Holdings received a subpoena from the NYAG which generally sought information and business records related to Energy Plus Holdings' sales, marketing and business practices. Energy Plus Holdings provided documents and information to the NYAG. On June 22, 2015, the NYAG issued another subpoena seeking additional information. Energy Plus Holdings provided responsive documents to this second subpoena. The Company does not expect the resolution of this matter to have a material impact on the Company’s consolidated financial position, results of operation, or cash flows. 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 GenOn Mid-Atlantic 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 GenOn Mid-Atlantic a similar letter with respect to the Chalk Point and Dickerson generating facilities, threatening to sue within 60 days if the generating facilities were not brought 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 CWA and Maryland environmental laws related to water. In August 2016, the court approved a consent decree to settle the matter. The consent decree requires: (1) improving the wastewater treatment systems at the Chalk Point and Dickerson facilities which was completed in October 2016; (2) completing supplemental environmental projects worth $1 million ; and (3) paying a civil penalty of $1 million . The Company has improved the wastewater treatment systems at the Chalk Point and Dickerson facilities and paid the civil penalty of $1 million . Midwest Generation New Source Review Litigation — In August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs, filed a complaint, or the Governments’ Complaint, in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior owner of the stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violations of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. In addition to seeking penalties of up to $37,500 per violation, per day, the complaint seeks an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at the units subject to the complaint and other remedies, which could go well beyond the requirements of the CPS. Several environmental groups intervened as plaintiffs in this litigation and filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010. In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be required to convince the court that the statute of limitations should be equitably tolled. The trial court did not address other counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against EME and ComEd. Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. The Company does not expect the resolution of this matter to have a material impact on the Company’s consolidated financial position, results of operations or cash flows. Potomac River Environmental Investigation — In March 2013, NRG Potomac River LLC received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site. NRG Potomac River LLC provided various responsive materials. In January 2016, DOEE advised NRG Potomac River LLC that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges. DOEE has indicated it believes that penalties are appropriate in light of the violations. NRG is currently reviewing the information provided by DOEE. Telephone Consumer Protection Act Purported Class Actions — Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey. The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On July 8, 2016, NRG filed a Rule 11 Motion seeking dismissal of NRG from the California case. The Rule 11 Motion was denied on August 16, 2016. Class certification hearings are scheduled on June 5, 2017 and June 19, 2017 in the New Jersey and California cases respectively. California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation. In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs have brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed demurrers in response to the plaintiffs' complaint. The demurrers were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016, defendants filed demurrers to the amended complaints. On November 18, 2016, the court sustained the demurrers and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA. Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. On August 3, 2016, the court approved a stipulation entered into by the parties. The stipulation provided that the plaintiffs would file an amended complaint by August 19, 2016, which they did on August 18, 2016. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On February 24, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on June 15, 2017 and defendants' reply is due on August 14, 2017. Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors — On September 15, 2016, plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants filed a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. Oral argument is scheduled for June 20, 2017. GenOn Noteholders' Lawsuit — On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, or collectively, the GenOn Notes, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to a services agreement between NRG and GenOn. Plaintiffs generally seek recovery of all monies paid under the services agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017. This agreement may be extended by mutual agreement of the parties.

Regulatory Matters (Notes)

Regulatory Matters (Notes)	12 Months Ended
	Dec. 31, 2016
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 parties 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. National Zero-Emission Credits for Nuclear Plants — Pursuant to legislation in Illinois , the Illinois Power Agency, or IPA, is to procure contracts for ZECs. The IPA is to procure ZECs through a process that would take into account environmental benefits, including the preservation of zero emission facilities. In New York, on August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES, which provided for ZECs which would provide more than $7.6 billion over 12 years in out-of-market subsidy payments to certain selected nuclear generating units in the state. Other states located in organized markets may also be considering the implementation of ZECs. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interferer with the wholesale power market. Current Administration and Changeover at FERC — FERC is currently without a quorum and cannot issue orders in contested proceedings until a new Commissioner is appointed. FERC’s day-to-day work can continue through authority that has been delegated to FERC Staff. With a new administration and three vacant positions at FERC, NRG’s business may be affected because its generation fleet is subject to changes in FERC regulatory policy. East Region Montgomery County Station Power Tax — On December 20, 2013, NRG 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 previous three years. Montgomery County seeks payment in the amount of $22 million , which includes tax, interest and penalties. NRG disputed the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment. Montgomery County filed an appeal, and on February 2, 2017, the Montgomery County Circuit Court affirmed the decision of the tax court. On February 17, 2017, Montgomery County filed an appeal to the Court of Special Appeals of Maryland. Retail MISO SECA — Green Mountain Energy previously provided competitive retail energy supply in the MISO region during the 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 eliminate seams charges and in the meantime, as a temporary measure, allowed them to recover transition charges known as SECA charges. 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. On September 16, 2015, FERC issued an order conditionally accepting those compliance filings, and setting for hearing and settlement proceedings issues related to service to certain Michigan customers during 2002 and 2003. 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. Subsequently, all remaining appeals either settled or were rejected by the Court. West Region Carlsbad Energy Center — On May 21, 2015, the CPUC approved the Carlsbad Energy Center PPTA for a nominally rated 500 MW five unit natural gas peaking plant. On December 7, 2015, three parties filed two petitions for a writ of review with the California Court of Appeal appealing the CPUC's decision. On November 30, 2016, the California Court of Appeals issued a decision affirming the CPUC's approval of the PPTA. The period in which to seek review of that decision in the California Supreme Court has passed, and the CPUC’s decision is now final. California Station Power — As the result of unfavorable final and non-appealable litigation, the Company has accrued a liability associated with its power plants’ consumption of station power in California, after August 30, 2010. The majority of the liability is associated with the Company's Encina, El Segundo, and Long Beach facilities. The Company has established an appropriate reserve and is awaiting final billing decisions from SCE.

Environmental Matters (Notes)

Environmental Matters (Notes)	12 Months Ended
	Dec. 31, 2016
Environmental Matters Disclosure [Abstract]
Environmental Matters	Environmental Matters NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry is facing new requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species have been put in place in recent years. In general, future laws 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 consolidated financial position, results of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this trend could change in the near term with respect to federal laws under the new U.S. presidential administration. The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO2 budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance. In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule. Water In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed. Byproducts, Wastes, Hazardous Materials and Contamination In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. The Company has evaluated the impact of the new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of December 31, 2016. East Region New Source Review — 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 2007, Midwest Generation received an NOV from the EPA alleging that past work at Crawford, Fisk, Joliet, Powerton, Waukegan and Will County generating stations violated NSR and other regulations. These alleged violations are the subject of the litigation described in Item 15 — Note 22, Commitments and Contingencies . In January 2009, GenOn received an NOV from the EPA alleging that past work at Keystone, Portland and Shawville generating stations 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. 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 generation stations violated regulations regarding NSR. Burton Island Old Ash Landfill — In January 2006, NRG's Indian River Power LLC 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, or the VCP. On February 4, 2008, DNREC issued findings that no further action was 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. 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. In December 2015, DNREC approved the Company's remediation design and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and on track for completion in 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016. In addition to the VCP, on May 29, 2008, DNREC requested that NRG's Indian River Power LLC 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. For further discussion of these matters, refer to Note 22 , Commitments and Contingencies .

Cash Flow Information (Notes)

Cash Flow Information (Notes)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (In millions) Interest paid, net of amount capitalized $ 1,106 $ 1,172 $ 1,067 Income taxes (refunded)/paid (a) 27 16 (6 ) Consent fee paid, preferred stock — — 5 Non-cash investing and financing activities: (Decrease)/additions to fixed assets for accrued capital expenditures (33 ) (24 ) 87 Decrease to fixed assets for accrued grants and related tax impact — — (711 ) Issuance of shares for EME acquisition — — (401 ) (a) In 2016 , the net income taxes paid reflect $29 million in income taxes paid and $2 million in income tax refunds. In 2015 , the net income taxes refunded are net of $17 million income taxes paid and $1 million income tax refunds. In 2014 , the net income taxes refunded are net of $15 million income taxes paid and $21 million income tax refunds.

Guarantees (Notes)

Guarantees (Notes)	12 Months Ended
	Dec. 31, 2016
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 Company's retail businesses. 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 $2.2 million as of December 31, 2016 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, 2016 Guarantees Under 1 Year 1-3 Years 3-5 Years Over 5 Years Total 2015 Total (In millions) Letters of credit and surety bonds $ 2,122 $ 80 $ — $ 15 $ 2,217 $ 1,899 Asset sales guarantee obligations — 420 — 257 677 257 Other guarantees — — 5 731 736 722 Total guarantees $ 2,122 $ 500 $ 5 $ 1,003 $ 3,630 $ 2,878 Letters of credit and surety bonds — As of December 31, 2016 , NRG and its consolidated subsidiaries were contingently obligated for a total of $2.2 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 obligations associated with future closure and maintenance of ash sites, 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 sales — 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. Other guarantees — NRG has issued other guarantees of obligations including payments under certain agreements with respect to certain of its unconsolidated subsidiaries, payment or performance by fuel providers and payment or reimbursement of credit support and deposits. 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, 2016
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, 2016 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress (In millions unless otherwise stated) South Texas Project Units 1 and 2, Bay City, TX 44.00 % $ 3,275 $ (1,734 ) $ 39 Big Cajun II Unit 3, New Roads, LA 58.00 % 204 123 — Cedar Bayou Unit 4, Baytown, TX 50.00 % 216 (67 ) 5 Keystone, Shelocta, PA 3.70 % 97 (48 ) — Conemaugh, New Florence, PA 3.72 % 103 (51 ) 1

Unaudited Quarterly Financial D

Unaudited Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2016
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 2016 December 31 September 30 June 30 March 31 (In millions, except per share data) Operating revenues $ 2,532 $ 3,952 $ 2,638 $ 3,229 Operating (loss)/income (791 ) 755 87 476 Net (loss)/income (1,055 ) 393 (276 ) 47 Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests (68 ) (9 ) (5 ) (35 ) Net (loss)/income attributable to NRG Energy, Inc. (987 ) 402 (271 ) 82 (Loss)/income available to Common Stockholders $ (987 ) $ 402 $ (193 ) $ 77 Weighted average number of common shares outstanding — basic 316 316 315 315 Net (loss)/income per weighted average common share — basic $ (3.13 ) $ 1.27 $ (0.61 ) $ 0.24 Weighted average number of common shares outstanding — diluted 316 317 315 315 Net (loss)/income per weighted average common share — diluted $ (3.13 ) $ 1.27 $ (0.61 ) $ 0.24 Quarter Ended 2015 December 31 September 30 June 30 March 31 (In millions, except per share data) Operating revenues $ 3,011 $ 4,434 $ 3,400 $ 3,829 Operating (loss)/income (4,727 ) 379 232 76 Net (loss)/income (6,358 ) 67 (9 ) (136 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (44 ) 1 5 (16 ) Net (loss)/income attributable to NRG Energy, Inc. (6,314 ) 66 (14 ) (120 ) (Loss)/income available to Common Stockholders $ (6,319 ) $ 61 $ (19 ) $ (125 ) Weighted average number of common shares outstanding — basic 315 331 333 336 Net (loss)/income per weighted average common share — basic $ (20.08 ) $ 0.18 $ (0.06 ) $ 0.37 Weighted average number of common shares outstanding — diluted 315 332 333 336 Net (loss)/income per weighted average common share — diluted $ (20.08 ) $ 0.18 $ (0.06 ) $ (0.37 )

Condensed Consolidating Financi

Condensed Consolidating Financial Information (Notes)	12 Months Ended
	Dec. 31, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	Condensed Consolidating Financial Information As of December 31, 2016 , the Company had outstanding $5.4 billion of Senior Notes due 2018 - 2027, 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 and NRG Yield, Inc. and its subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2016 : Ace Energy, Inc. NEO Freehold-Gen LLC NRG Operating Services, Inc. Allied Warranty LLC NEO Power Services Inc. NRG Oswego Harbor Power Operations Inc. Arthur Kill Power LLC New Genco GP, LLC NRG PacGen Inc. Astoria Gas Turbine Power LLC Norwalk Power LLC NRG Portable Power LLC Bayou Cove Peaking Power LLC NRG Affiliate Services Inc. NRG Power Marketing LLC BidURenergy, Inc. NRG Artesian Energy LLC NRG Reliability Solutions LLC Cabrillo Power I LLC NRG Arthur Kill Operations Inc. NRG Renter's Protection LLC Cabrillo Power II LLC NRG Astoria Gas Turbine Operations Inc. NRG Retail LLC Carbon Management Solutions LLC NRG Bayou Cove LLC NRG Retail Northeast LLC Cirro Group, Inc. NRG Business Solutions LLC NRG Rockford Acquisition LLC Cirro Energy Services, Inc. NRG Cabrillo Power Operations Inc. NRG Saguaro Operations Inc. Clean Edge Energy LLC NRG California Peaker Operations LLC NRG Security LLC Conemaugh Power LLC NRG Cedar Bayou Development Company, LLC NRG Services Corporation Connecticut Jet Power LLC NRG Connected Home LLC NRG SimplySmart Solutions LLC Cottonwood Development LLC NRG Connecticut Affiliate Services Inc. NRG South Central Affiliate Services Inc. Cottonwood Energy Company LP NRG Construction LLC NRG South Central Generating LLC Cottonwood Generating Partners I LLC NRG Curtailment Solutions LLC NRG South Central Operations Inc. Cottonwood Generating Partners II LLC NRG Development Company Inc. NRG South Texas LP Cottonwood Generating Partners III LLC NRG Devon Operations Inc. NRG Texas C&I Supply LLC Cottonwood Technology Partners LP NRG Dispatch Services LLC NRG Texas Gregory LLC Devon Power LLC NRG Distributed Generation PR LLC NRG Texas Holding Inc. Dunkirk Power LLC NRG Dunkirk Operations Inc. NRG Texas LLC Eastern Sierra Energy Company LLC NRG El Segundo Operations Inc. NRG Texas Power LLC El Segundo Power, LLC NRG Energy Efficiency-L LLC NRG Warranty Services LLC El Segundo Power II LLC NRG Energy Efficiency-P LLC NRG West Coast LLC Energy Alternatives Wholesale, LLC NRG Energy Labor Services LLC NRG Western Affiliate Services Inc. Energy Choice Solutions, LLC NRG ECOKAP Holdings, LLC O'Brien Cogeneration, Inc. II NRG Curtailment Solutions, Inc. NRG Energy Services Group LLC ONSITE Energy, Inc. Energy Plus Holdings LLC NRG Energy Services International Inc. Oswego Harbor Power LLC Energy Plus Natural Gas LLC NRG Energy Services LLC RE Retail Receivables, LLC Energy Protection Insurance Company NRG Generation Holdings, Inc. Reliant Energy Northeast LLC Everything Energy LLC NRG Home & Business Solutions LLC Reliant Energy Power Supply, LLC Forward Home Security, LLC NRG Home Solutions LLC Reliant Energy Retail Holdings, LLC GCP Funding Company, LLC NRG Home Solutions Product LLC Reliant Energy Retail Services, LLC Green Mountain Energy Company NRG Homer City Services LLC RERH Holdings LLC Gregory Partners, LLC NRG Huntley Operations Inc. Saguaro Power LLC Gregory Power Partners LLC NRG HQ DG LLC Somerset Operations Inc. Huntley Power LLC NRG Identity Protect LLC Somerset Power LLC Independence Energy Alliance LLC NRG Ilion Limited Partnership Texas Genco Financing Corp. Independence Energy Group LLC NRG Ilion LP LLC Texas Genco GP, LLC Independence Energy Natural Gas LLC NRG International LLC Texas Genco Holdings, Inc. Indian River Operations Inc. NRG Maintenance Services LLC Texas Genco LP, LLC Indian River Power LLC NRG Mextrans Inc. Texas Genco Operating Services, LLC Keystone Power LLC NRG MidAtlantic Affiliate Services Inc. Texas Genco Services, LP Langford Wind Power LLC NRG Middletown Operations Inc. US Retailers LLC NRG Home Services LLC NRG Montville Operations Inc. Vienna Operations Inc. Louisiana Generating LLC NRG New Roads Holdings LLC Vienna Power LLC Meriden Gas Turbines LLC NRG North Central Operations Inc. WCP (Generation) Holdings LLC Middletown Power LLC NRG Northeast Affiliate Services Inc. West Coast Power LLC Montville Power LLC NRG Norwalk Harbor Operations Inc. NEO Corporation NRG GreenCo, LLC NRG Business Services LLC NRG GreenCo Holdings, 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, 2016 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 7,509 $ 5,082 $ — $ (240 ) $ 12,351 Operating Costs and Expenses Cost of operations 5,402 3,355 42 (244 ) 8,555 Depreciation and amortization 565 776 26 — 1,367 Impairment losses 378 540 — — 918 Selling, general and administrative 415 397 289 — 1,101 Acquisition-related transaction and integration costs — 1 7 — 8 Development costs — 60 30 — 90 Total operating costs and expenses 6,760 5,129 394 (244 ) 12,039 Gain/(loss) on sale of assets — 294 (79 ) — 215 Operating Income/(Loss) 749 247 (473 ) 4 527 Other Income/(Expense) Equity in (losses)/earnings of consolidated subsidiaries (148 ) (58 ) 313 (107 ) — Equity in earnings/(losses) of unconsolidated affiliates 5 37 (5 ) (10 ) 27 Impairment losses on investments — (268 ) — — (268 ) Other income/(loss), net 4 46 (6 ) (2 ) 42 Net loss on debt extinguishment — (4 ) (138 ) — (142 ) Interest expense (15 ) (574 ) (472 ) — (1,061 ) Total other expense (154 ) (821 ) (308 ) (119 ) (1,402 ) Income/(Loss) Before Income Taxes 595 (574 ) (781 ) (115 ) (875 ) Income tax expense/(benefit) (1 ) 18 (63 ) 62 16 Net Income/(Loss) 596 (592 ) (718 ) (177 ) (891 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (103 ) 56 (70 ) (117 ) Net Income/(Loss) Attributable to NRG Energy, Inc. $ 596 $ (489 ) $ (774 ) $ (107 ) $ (774 ) (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, 2016 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Income/(Loss) $ 596 $ (592 ) $ (718 ) $ (177 ) $ (891 ) Other Comprehensive Income/(Loss), net of tax Unrealized gain on derivatives, net — 32 89 (86 ) 35 Foreign currency translation adjustments, net (1 ) (1 ) (1 ) 2 (1 ) Available-for-sale securities, net — — 1 — 1 Defined benefit plan, net 36 (23 ) (51 ) 41 3 Other comprehensive income 35 8 38 (43 ) 38 Comprehensive Income/(Loss) 631 (584 ) (680 ) (220 ) (853 ) Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (103 ) 56 (70 ) (117 ) Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. 631 (481 ) (736 ) (150 ) (736 ) Dividends for preferred shares — — 5 — 5 Gain on redemption of preferred shares — — (78 ) — (78 ) Comprehensive Income/(Loss) Available for Common Stockholders $ 631 $ (481 ) $ (663 ) $ (150 ) $ (663 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2016 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) ASSETS Current Assets Cash and cash equivalents $ — $ 1,650 $ 323 $ — $ 1,973 Funds deposited by counterparties 2 — — — 2 Restricted cash 11 435 — — 446 Accounts receivable - trade, net 734 429 3 — 1,166 Accounts receivable - Affiliate 309 (241 ) 200 (262 ) 6 Inventory 482 629 — — 1,111 Derivative instruments 962 305 — (205 ) 1,062 Cash collateral posted in support of energy risk management activities 37 166 — — 203 Current assets held-for-sale — 9 — — 9 Prepayments and other current assets 76 279 62 — 417 Total current assets 2,613 3,661 588 (467 ) 6,395 Net Property, Plant and Equipment 4,216 13,472 251 (27 ) 17,912 Other Assets Investment in subsidiaries 837 1,973 10,128 (12,938 ) — Equity investments in affiliates (14 ) 1,129 5 — 1,120 Notes receivable, less current portion — 17 (76 ) 76 17 Goodwill 359 303 — — 662 Intangible assets, net 592 1,447 — (3 ) 2,036 Nuclear decommissioning trust fund 610 — — — 610 Deferred income taxes 3 868 (646 ) — 225 Derivative instruments 143 60 36 (50 ) 189 Non-current assets held for sale — 10 — — 10 Other non-current assets 67 784 328 — 1,179 Total other assets 2,597 6,591 9,775 (12,915 ) 6,048 Total Assets $ 9,426 $ 23,724 $ 10,614 $ (13,409 ) $ 30,355 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and capital leases $ — $ 1,202 $ (58 ) $ 76 $ 1,220 Accounts payable 499 362 34 — 895 Accounts payable - affiliate 655 1,834 (2,227 ) (262 ) — Derivative instruments 947 342 — (205 ) 1,084 Cash collateral received in support of energy risk management activities 2 — — — 2 Accrued interest expense 3 94 123 — 220 Other accrued expenses 110 140 293 — 543 Other current liabilities 204 166 48 — 418 Total current liabilities 2,420 4,140 (1,787 ) (391 ) 4,382 Other Liabilities Long-term debt and capital leases 244 10,302 7,460 — 18,006 Nuclear decommissioning reserve 287 — — — 287 Nuclear decommissioning trust liability 339 — — — 339 Postretirement and other benefit obligations 114 189 250 — 553 Deferred income taxes 186 (1,094 ) 928 — 20 Derivative instruments 157 187 — (50 ) 294 Out-of-market contracts 80 960 — — 1,040 Non-current liabilities held-for-sale — 12 — — 12 Other non-current liabilities 283 573 74 — 930 Total non-current liabilities 1,690 11,129 8,712 (50 ) 21,481 Total Liabilities 4,110 15,269 6,925 (441 ) 25,863 2.822% Preferred Stock — — — — — Redeemable noncontrolling interest in subsidiaries — 46 — — 46 Stockholders' Equity 5,316 8,409 3,689 (12,968 ) 4,446 Total Liabilities and Stockholders' Equity $ 9,426 $ 23,724 $ 10,614 $ (13,409 ) $ 30,355 (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, 2016 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net income/(loss) $ 596 $ (592 ) $ (718 ) $ (177 ) $ (891 ) Adjustments to reconcile net income/(loss) to net cash provided by operating activities: Distributions from unconsolidated affiliates — 89 — (8 ) 81 Equity in earnings of unconsolidated affiliates (5 ) (37 ) 5 10 (27 ) Depreciation and amortization 565 776 26 — 1,367 Provision for bad debts 41 7 — — 48 Amortization of nuclear fuel 49 — — — 49 Amortization of financing costs and debt discount/premiums — (18 ) 21 — 3 Adjustment to loss on debt extinguishment — 4 17 — 21 Amortization of intangibles and out-of-market contracts 39 52 — — 91 Amortization of unearned equity compensation — — 10 — 10 Gain on sale of assets and equity method investments, net — (294 ) 70 — (224 ) Impairment losses 378 808 — — 1,186 Changes in derivative instruments (77 ) 136 (36 ) — 23 Changes in deferred income taxes and liability for uncertain tax benefits (1 ) 18 (60 ) — (43 ) Changes in collateral deposits supporting energy risk management activities 437 (72 ) — — 365 Proceeds from sale of emission allowances 47 — — — 47 Changes in nuclear decommissioning trust liability 41 — — — 41 Cash (used)/provided by changes in other working capital (1,806 ) 364 1,192 175 (75 ) Net Cash Provided by Operating Activities 304 1,241 527 — 2,072 Cash Flows from Investing Activities Dividends from NRG Yield, Inc. — — 81 (81 ) — Acquisition of September 2016 Drop Down Assets, net of cash acquired — (77 ) — 77 — Intercompany dividends — — 12 (12 ) — Acquisition of businesses, net of cash acquired — (209 ) — — (209 ) Capital expenditures (180 ) (1,016 ) (48 ) — (1,244 ) Increase in restricted cash, net (4 ) (25 ) — — (29 ) Increase in restricted cash - U.S. DOE projects — (3 ) — — (3 ) Decrease in notes receivable — 17 — — 17 Proceeds from renewable energy grants — 36 — — 36 Purchases of emission allowances, net of proceeds (1 ) — — — (1 ) Investments in nuclear decommissioning trust securities (551 ) — — — (551 ) Proceeds from sales of nuclear decommissioning trust fund securities 510 — — — 510 Proceeds from sale of assets, net — 619 17 — 636 Investments in unconsolidated affiliates 3 (37 ) — — (34 ) Other 27 13 8 — 48 Net Cash (Used)/Provided by Investing Activities (196 ) (682 ) 70 (16 ) (824 ) Cash Flows from Financing Activities Dividends from NRG Yield, Inc. — (81 ) — 81 — Payments (for)/from intercompany loans (52 ) (49 ) 101 — — Acquisition of September 2016 Drop Down Assets, net of cash acquired — — 77 (77 ) — Intercompany dividends (52 ) 40 — 12 — Payment of dividends to preferred and common stockholders — — (76 ) — (76 ) Net receipts from settlement of acquired derivatives that include financing elements — 151 — — 151 Payments for preferred shares — — (226 ) — (226 ) Distributions from, net of contributions to noncontrolling interests in subsidiaries — (156 ) — — (156 ) Proceeds from issuance of common stock — — 1 — 1 Proceeds from issuance of long-term debt — 1,387 4,140 — 5,527 Payments for short and long-term debt (1 ) (988 ) (4,924 ) — (5,913 ) Payment of debt issuance costs and hedging costs — (29 ) (60 ) — (89 ) Other (3 ) (10 ) — — (13 ) Net Cash (Used)/Provided by Financing Activities (108 ) 265 (967 ) 16 (794 ) Effect of exchange rate changes on cash and cash equivalents — 1 — — 1 Net Increase/(Decrease) in Cash and Cash Equivalents — 825 (370 ) — 455 Cash and Cash Equivalents at Beginning of Period — 825 693 — 1,518 Cash and Cash Equivalents at End of Period $ — $ 1,650 $ 323 $ — $ 1,973 (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, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 10,024 $ 4,768 $ — $ (118 ) $ 14,674 Operating Costs and Expenses Cost of operations 7,712 3,176 14 (118 ) 10,784 Depreciation and amortization 787 759 20 — 1,566 Impairment losses 4,655 375 — — 5,030 Selling, general and administrative 467 382 350 — 1,199 Acquisition-related transactions and integration costs 1 (5 ) 14 — 10 Development costs — 53 93 — 146 Total operating costs and expenses 13,622 4,740 491 (118 ) 18,735 Gain on postretirement benefits curtailment — 21 — — 21 Operating (Loss)/Income (3,598 ) 49 (491 ) — (4,040 ) Other Income/(Expense) Equity in losses of consolidated subsidiaries (86 ) (29 ) (2,799 ) 2,914 — Equity in earnings of unconsolidated affiliates 8 37 — (9 ) 36 Impairment losses on investments — (25 ) (31 ) — (56 ) Other income, net 4 29 — — 33 Loss on sale of equity method investment — — (14 ) — (14 ) Net gain on debt extinguishment — 56 19 — 75 Interest expense (18 ) (564 ) (546 ) — (1,128 ) Total other expense (92 ) (496 ) (3,371 ) 2,905 (1,054 ) Loss Before Income Taxes (3,690 ) (447 ) (3,862 ) 2,905 (5,094 ) Income tax (benefit)/expense (1,104 ) (96 ) 2,489 53 1,342 Net Loss (2,586 ) (351 ) (6,351 ) 2,852 (6,436 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (23 ) 31 (62 ) (54 ) Net Loss Attributable to NRG Energy, Inc. $ (2,586 ) $ (328 ) $ (6,382 ) $ 2,914 $ (6,382 ) (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, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Loss $ (2,586 ) $ (351 ) $ (6,351 ) $ 2,852 $ (6,436 ) Other Comprehensive (Loss)/Income, net of tax Unrealized (loss)/gain on derivatives, net (9 ) (13 ) 48 (41 ) (15 ) Foreign currency translation adjustments, net — (7 ) (4 ) — (11 ) Available-for-sale securities, net — (1 ) 18 — 17 Defined benefit plan, net (22 ) (15 ) (42 ) 89 10 Other comprehensive (loss)/income (31 ) (36 ) 20 48 1 Comprehensive Loss (2,617 ) (387 ) (6,331 ) 2,900 (6,435 ) Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (42 ) 31 (62 ) (73 ) Comprehensive Loss Attributable to NRG Energy, Inc. (2,617 ) (345 ) (6,362 ) 2,962 (6,362 ) Dividends for preferred shares — — 20 — 20 Comprehensive Loss Available for Common Stockholders $ (2,617 ) $ (345 ) $ (6,382 ) $ 2,962 $ (6,382 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) ASSETS Current Assets Cash and cash equivalents $ — $ 825 $ 693 $ — $ 1,518 Funds deposited by counterparties 55 51 — — 106 Restricted cash 5 409 — — 414 Accounts receivable - trade, net 851 304 2 — 1,157 Inventory 570 682 — — 1,252 Derivative instruments 1,202 871 — (158 ) 1,915 Cash collateral posted in support of energy risk management activities 474 94 — — 568 Accounts receivable - affiliate 395 260 571 (1,222 ) 4 Current assets held-for-sale — 6 — — 6 Prepayments and other current assets 93 287 71 — 451 Total current assets 3,645 3,789 1,337 (1,380 ) 7,391 Net Property, Plant and Equipment 4,767 13,773 219 (27 ) 18,732 Other Assets Investment in subsidiaries 842 2,244 11,039 (14,125 ) — Equity investments in affiliates (14 ) 1,160 1 (102 ) 1,045 Notes receivable, less current portion — 46 7 — 53 Goodwill 697 302 — — 999 Intangible assets, net 763 1,551 2 (6 ) 2,310 Nuclear decommissioning trust fund 561 — — — 561 Derivative instruments 153 184 — (32 ) 305 Deferred income taxes (6 ) 815 (642 ) — 167 Non-current assets held for sale — 105 — — 105 Other non-current assets 80 749 385 — 1,214 Total other assets 3,076 7,156 10,792 (14,265 ) 6,759 Total Assets $ 11,488 $ 24,718 $ 12,348 $ (15,672 ) $ 32,882 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and capital leases $ 2 $ 460 $ 19 $ — $ 481 Accounts payable 553 277 39 — 869 Accounts payable - affiliate 151 2,000 (929 ) (1,222 ) — Derivative instruments 1,130 749 — (158 ) 1,721 Cash collateral received in support of energy risk management activities 55 51 — — 106 Accrued interest expense 5 91 147 (1 ) 242 Other accrued expenses 122 151 295 — 568 Current liabilities held-for-sale — 2 — — 2 Other current liabilities 192 187 7 — 386 Total current liabilities 2,210 3,968 (422 ) (1,381 ) 4,375 Other Liabilities Long-term debt and capital leases 302 10,496 8,185 — 18,983 Nuclear decommissioning reserve 326 — — — 326 Nuclear decommissioning trust liability 283 — — — 283 Postretirement and other benefit obligations 236 200 152 — 588 Deferred income taxes 179 (1,088 ) 928 — 19 Derivative instruments 301 224 — (32 ) 493 Out-of-market contracts 95 1,051 — — 1,146 Non-current liabilities held-for-sale — 4 — — 4 Other non-current liabilities 318 535 47 — 900 Total non-current liabilities 2,040 11,422 9,312 (32 ) 22,742 Total Liabilities 4,250 15,390 8,890 (1,413 ) 27,117 2.822% Preferred Stock — — 302 — 302 Redeemable noncontrolling interest in subsidiaries — 29 — — 29 Stockholders' Equity 7,238 9,299 3,156 (14,259 ) 5,434 Total Liabilities and Stockholders' Equity $ 11,488 $ 24,718 $ 12,348 $ (15,672 ) $ 32,882 (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, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net loss $ (2,586 ) $ (351 ) $ (6,351 ) $ 2,852 $ (6,436 ) Adjustments to reconcile net loss to net cash provided by operating activities: Distributions from unconsolidated affiliates 3 91 — (21 ) 73 Equity in earnings of unconsolidated affiliates (8 ) (37 ) — 9 (36 ) Depreciation and amortization 787 759 20 — 1,566 Provision for bad debts 58 3 3 — 64 Amortization of nuclear fuel 45 — — — 45 Amortization of financing costs and debt discount/premiums — (37 ) 26 — (11 ) Adjustment to gain on debt extinguishment — (56 ) (19 ) — (75 ) Amortization of intangibles and out-of-market contracts 52 29 — — 81 Amortization of unearned equity compensation — — 41 — 41 Gain on postretirement benefits curtailment — (21 ) — — (21 ) Loss on sale of assets — — 14 — 14 Impairment losses 4,655 400 31 — 5,086 Changes in derivative instruments 264 (31 ) — — 233 Changes in deferred income taxes and liability for uncertain tax benefits (1,092 ) (237 ) 2,655 — 1,326 Changes in nuclear decommissioning trust liability (2 ) — — — (2 ) Changes in collateral deposits supporting energy risk management activities (360 ) (21 ) — — (381 ) Cash (used)/provided by changes in other working capital (8,744 ) (847 ) 12,173 (2,840 ) (258 ) Net Cash (Used)/Provided by Operating Activities (6,928 ) (356 ) 8,593 — 1,309 Cash Flows from Investing Activities Dividends from NRG Yield, Inc. — — 70 (70 ) — Intercompany dividends — — 33 (33 ) — Acquisition of 2015 Drop Down Assets, net of cash acquired — (698 ) — 698 — Acquisition of businesses, net of cash acquired — (31 ) — — (31 ) Capital expenditures (316 ) (908 ) (59 ) — (1,283 ) (Increase)/decrease in restricted cash, net (1 ) 9 — — 8 Decrease in restricted cash - U.S. DOE projects — 34 1 — 35 Decrease in notes receivable — 18 — — 18 Proceeds from renewable energy grants — 82 — — 82 Purchases of emission allowances, net of proceeds 41 — — — 41 Investments in nuclear decommissioning trust fund securities (629 ) — — — (629 ) Proceeds from sales of nuclear decommissioning trust fund securities 631 — — — 631 Proceeds from sale of assets, net — 1 26 — 27 Investments in unconsolidated affiliates 1 (357 ) (39 ) — (395 ) Other — 11 — — 11 Net Cash (Used)/Provided by Investing Activities (273 ) (1,839 ) 32 595 (1,485 ) Cash Flows from Financing Activities Dividends from NRG Yield, Inc. — (70 ) — 70 — Intercompany dividends — (33 ) — 33 — Payments from/(for) intercompany loans 7,183 1,258 (8,441 ) — — Acquisition of 2015 Drop Down Assets, net of cash acquired — — 698 (698 ) — Payment of dividends to preferred stockholders — — (201 ) — (201 ) Net receipts from acquired derivatives that include financing elements — 196 — — 196 Payment for treasury stock — — (437 ) — (437 ) Distributions from, net of contributions to, noncontrolling interests in subsidiaries — 47 — — 47 Proceeds from sale of noncontrolling interests in subsidiaries — 600 — — 600 Proceeds from issuance of common stock — — 1 — 1 Proceeds from issuance of long-term debt — 953 51 — 1,004 Payments of short and long-term debt — (1,353 ) (246 ) — (1,599 ) Payment of debt issuance and hedging costs — (21 ) — — (21 ) Other — (22 ) — — (22 ) Net Cash Provided/(Used) by Financing Activities 7,183 1,555 (8,575 ) (595 ) (432 ) Effect of exchange rate changes on cash and cash equivalents — 10 — — 10 Net (Decrease)/Increase in Cash and Cash Equivalents (18 ) (630 ) 50 — (598 ) Cash and Cash Equivalents at Beginning of Period 18 1,455 643 — 2,116 Cash and Cash Equivalents at End of Period $ — $ 825 $ 693 $ — $ 1,518 (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, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 9,974 $ 6,287 $ — $ (393 ) $ 15,868 Operating Costs and Expenses Cost of operations 7,909 4,220 4 (325 ) 11,808 Depreciation and amortization 801 706 16 — 1,523 Impairment losses — 119 — (22 ) 97 Selling, general and administrative 333 379 304 — 1,016 Acquisition-related transaction and integration costs 3 15 66 — 84 Development costs — 32 56 — 88 Total operating costs and expenses 9,046 5,471 446 (347 ) 14,616 Gain on sale of assets — 19 — — 19 Operating Income/(Loss) 928 835 (446 ) (46 ) 1,271 Other Income/(Expense) Equity in earnings of consolidated subsidiaries 317 219 775 (1,311 ) — Equity in earnings of unconsolidated affiliates 13 33 — (8 ) 38 Other income, net 7 14 3 (2 ) 22 Gain on sale of equity method investment — 18 — — 18 Loss on debt extinguishment — (9 ) (86 ) — (95 ) Interest expense (19 ) (525 ) (575 ) — (1,119 ) Total other income/(expense) 318 (250 ) 117 (1,321 ) (1,136 ) Income/(Loss) Before Income Taxes 1,246 585 (329 ) (1,367 ) 135 Income tax expense/(benefit) 322 159 (478 ) — 3 Net Income 924 426 149 (1,367 ) 132 Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests — 57 15 (74 ) (2 ) Net Income Attributable to NRG Energy, Inc $ 924 $ 369 $ 134 $ (1,293 ) $ 134 (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, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Income $ 924 $ 426 $ 149 $ (1,367 ) $ 132 Other Comprehensive (Loss)/Income, net of tax Unrealized loss on derivatives, net (49 ) (89 ) (215 ) 308 (45 ) Foreign currency translation adjustments, net — (12 ) 4 — (8 ) Available-for-sale securities, net — 1 (8 ) — (7 ) Defined benefit plan, net 5 (104 ) 20 (50 ) (129 ) Other comprehensive loss (44 ) (204 ) (199 ) 258 (189 ) Comprehensive Income/(Loss) 880 222 (50 ) (1,109 ) (57 ) Less: Comprehensive income attributable to noncontrolling interest — 67 15 (74 ) 8 Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. 880 155 (65 ) (1,035 ) (65 ) Dividends for preferred shares — — 56 — 56 Comprehensive Income/(Loss) Available for Common Stockholders $ 880 $ 155 $ (121 ) $ (1,035 ) $ (121 ) (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, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net income $ 924 $ 426 $ 149 $ (1,367 ) $ 132 Adjustments to reconcile net income to net cash provided by operating activities: Distributions from unconsolidated affiliates — 87 — — 87 Equity in earnings of unconsolidated affiliates (13 ) (33 ) — 8 (38 ) Depreciation and amortization 801 706 16 — 1,523 Provision for bad debts 64 — — — 64 Amortization of nuclear fuel 46 — — — 46 Amortization of financing costs and debt discount/premiums — (40 ) 28 — (12 ) Adjustment to loss on debt extinguishment — 8 17 — 25 Amortization of intangibles and out-of-market contracts 65 (1 ) — — 64 Amortization of unearned equity compensation — — 42 — 42 Gain on sale of assets — (4 ) — — (4 ) Impairment losses — 119 — (22 ) 97 Changes in derivative instruments (149 ) 88 — — (61 ) Changes in deferred income taxes and liability for uncertain tax benefits 242 (115 ) (281 ) — (154 ) Changes in nuclear decommissioning trust liability 19 — — — 19 Changes in collateral deposits supporting energy risk management activities 101 45 — — 146 Cash provided/(used) by changes in other working capital 686 (958 ) (1,575 ) 1,381 (466 ) Net Cash Provided/(Used) by Operating Activities 2,786 328 (1,604 ) — 1,510 Cash Flows from Investing Activities Dividends from NRG Yield, Inc. — — 60 (60 ) — Acquisition of business, net of cash acquired — (25 ) (2,911 ) — (2,936 ) Capital expenditures (252 ) (619 ) (38 ) — (909 ) Decrease in restricted cash — 57 — — 57 (Increase)/decrease in restricted cash - U.S. DOE projects — (209 ) 3 — (206 ) Decrease in notes receivable — 25 — — 25 Proceeds from renewable energy grants — 916 — — 916 Purchases of emission allowances, net of proceeds (16 ) — — — (16 ) Investments in nuclear decommissioning trust fund securities (619 ) — — — (619 ) Proceeds from sales of nuclear decommissioning trust fund securities 600 — — — 600 Proceeds from sale of assets, net — — 203 — 203 Investments in unconsolidated affiliates, net — (25 ) (78 ) — (103 ) Other — 85 — — 85 Net Cash (Used)/Provided by Investing Activities (287 ) 205 (2,761 ) (60 ) (2,903 ) Cash Flows from Financing Activities Dividends from NRG Yield, Inc. — (60 ) — 60 — Payments (for)/from intercompany loans (2,523 ) (685 ) 3,208 — Payment for dividends to preferred stockholders — — (196 ) — (196 ) Net receipts from acquired derivatives that include financing elements — 9 — — 9 Payment for treasury stock — — (39 ) — (39 ) Distributions from, net of contributions to, noncontrolling interests in subsidiaries — 189 — — 189 Proceeds from sale of noncontrolling interests in subsidiaries — 630 — — 630 Proceeds from issuance of common stock — — 21 — 21 Proceeds from issuance of long-term debt — 1,182 3,381 — 4,563 Payments of short and long-term debt — (1,160 ) (2,667 ) — (3,827 ) Payment of debt issuance and hedging costs — (39 ) (28 ) — (67 ) Other (14 ) (4 ) — — (18 ) Net Cash (Used)/Provided by Financing Activities (2,537 ) 62 3,680 60 1,265 Effect of exchange rate changes on cash and cash equivalents — (10 ) — — (10 ) Net (Decrease)/Increase in Cash and Cash Equivalents (38 ) 585 (685 ) — (138 ) Cash and Cash Equivalents at Beginning of Period 56 870 1,328 — 2,254 Cash and Cash Equivalents at End of Period $ 18 $ 1,455 $ 6

Summary of Significant Accoun38

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Summary of Significant Accounting Policies Disclosure
Basis of Presentation	The Company's consolidated financial statements have been prepared in accordance with GAAP. The ASC, established by the FASB, is the source of authoritative 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 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 The Company's businesses are segregated as follows: Generation (previously named Generation/Business), which includes generation, international and BETM (previously part of Corporate); Retail which includes Mass customers (previously Retail Mass), and Business Solutions, which includes C&I customers and other distributed and reliability products (previously in the Generation segment); Renewables (previously named NRG Renew), which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. The Company's corporate segment include residential solar (previously part of NRG Home) and electric vehicle services. During 2016, the Company began reporting the results of its residential solar business in its corporate segment and its international business in its Generation segment. The Company's segment structure and its allocation of corporate expenses were updated to reflect how management 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.
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. Of these funds, as of December 31, 2016, approximately $53 million is designated for current debt service payments, $51 million is designated to fund operating expenses, and $58 million is designated to fund distributions, with the remaining $284 million restricted for reserves including debt service, performance obligations and other reserves, as well as capital expenditures.
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. In addition, the Company considers a reserve for doubtful accounts based on the credit worthiness of the customers and continually reviews and adjusts for current economic trends that might impact the level of future credit losses. The reserve represents management's best estimate of uncollectible amounts. As of December 31, 2016 and 2015, the allowance for doubtful accounts was $30 million and $21 million , respectively.
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 weighted average cost. The Company removes these inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the fuel oil, coal, raw materials, and spare parts costs in the ordinary course of business. Finished goods inventory is valued at the lower of cost or net realizable value with cost being determined on a first-in first-out basis. The Company removes these inventories as they are sold to customers. 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 or, in the case of business acquisitions, fair value; however, impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. See Note 3 , Business Acquisitions and Dispositions , for more information on acquired property, plant and equipment. 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 indicated 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 consolidated 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 an other-than-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 .
Project Development Costs and Capitalized Interest	Development Costs and Capitalized Interest Development costs 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 interest, and capitalized project development costs are reclassified to property, plant and equipment and depreciated 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. 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, 2016 , 2015 , and 2014 , was $43 million , $30 million , and $29 million , respectively.
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. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt.
Intangible Assets	Intangible Assets Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, power purchase agreements, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, the Company 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. As of December 31, 2016 and 2015, the Company had accumulated amortization related to its intangible assets of $1.8 billion and $1.5 billion , respectively. 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, 2016 . 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. The Company first assesses 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. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. 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 the implied fair value, an impairment charge is recognized for the excess. For further discussion of goodwill and goodwill impairment losses recognized during 2016 and 2015, refer to Note 11 , Goodwill and Other Intangibles .
Income Taxes	Income Taxes The Company 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. The Company 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. The Company reports some of its 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. The Company measures its 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 its 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. The Company 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 the Company'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 — The Company records its bank of emission allowances as part of 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. The Company 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 $154 million , $165 million and $387 million for the years ended December 31, 2016 , 2015 , and 2014 , 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. The Company recorded receivables for unbilled revenues of $321 million , $309 million and $341 million as of December 31, 2016 , 2015 , and 2014 , respectively, for retail energy sales and services. Consumer product revenues are recognized when title and risk of loss pass to the retailer, distributor, or end-customer and when all of the following have occurred: a firm sales agreement is in place, delivery has occurred, pricing is fixed and determinable, and collection is reasonably assured. Revenue is recognized as the net amount expected to be received after deducting estimated amounts for product returns, discounts, and allowances based on historical return rates and reasonable judgment.
Lease, Policy [Policy Text Block]	Lessor Accounting Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. Many of these agreements are accounted for as operating leases under ASC 840 Leases. Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease. Contingent rental income recognized in the years ended December 31, 2016 , 2015 , and 2014 was $936 million , $777 million , and $544 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, 2016 , 2015 , and 2014 , the Company's revenues and cost of operations included gross receipts taxes of $102 million , $110 million , and $108 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 The Company 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. The Company's primary derivative instruments are power purchase or 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, the Company 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 a 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. In this case, the gain or loss previously deferred in accumulated OCI would be frozen until the underlying hedged instrument is delivered unless the transactions being hedged are no longer probable of occurring in which case the amount in 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 consolidated 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 consolidated statements of operations. For the years ended December 31, 2016 , 2015 , and 2014 , amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2016 , 2015 , and 2014 were $(11) million , $(10) million and $1 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 payable, 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 The Company accounts for 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, the Company 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 The Company offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. The Company 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 the Company'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. The Company'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. The Company 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 The Company 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 market stock 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 the Company'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 The Company 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 the Company 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. For certain investments that relate to tax equity arrangements, equity earnings are allocated using the hypothetical liquidation at book value, or HLBV, method which is described below. Distributions from equity method investments that represent earnings on the Company's investment are included within cash flows from operating activities and distributions from equity method investments that represent a return of the Company's investment are included within cash flows from investing activities.
Tax Equity Arrangements, Policy [Policy Text Block]	Tax Equity Arrangements The Company’s redeemable noncontrolling interest in subsidiaries and noncontrolling interest, included in stockholders' equity, represents third-party interests in the net assets under certain tax equity arrangements, which are consolidated by the Company, that have been entered into to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits. The Company has determined that the provisions in the contractual agreements of these structures represent substantive profit sharing arrangements. Further, the Company has determined that the appropriate methodology for calculating the noncontrolling interest and redeemable noncontrolling interest that reflects the substantive profit sharing arrangements is a balance sheet approach utilizing the HLBV method. Under the HLBV method, the amounts reported as noncontrolling interest and redeemable noncontrolling interests represent the amounts the investors that are party to the tax equity arrangements would hypothetically receive at each balance sheet date under the liquidation provisions of the contractual agreements, assuming the net assets of the funding structures were liquidated at their recorded amounts determined in accordance with GAAP. The investors’ interests in the results of operations of the funding structures are determined as the difference in noncontrolling interest and redeemable noncontrolling interests at the start and end of each reporting period, after taking into account any capital transactions between the structures and the funds’ investors. The calculations utilized to apply the HLBV method include estimated calculations of taxable income or losses for each reporting period.
Sale Leaseback Transactions, Policy [Policy Text Block]	Sale-Leaseback Arrangements NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneous leaseback to the Company. In accordance with ASC 840-40, Sale-Leaseback Transactions , if the seller-lessee retains, through the leaseback, substantially all of the benefits and risks incident to the ownership of the property sold, the sale-leaseback transaction is accounted for as a financing arrangement. An example of this type of continuing involvement would include an option to repurchase the assets or the buyer-lessor having the option to sell the assets back to the Company. This provision is included in most of the Company’s sale-leaseback arrangements. As such, the Company accounts for these arrangements as financings. Under the financing method, the Company does not recognize as income any of the sale proceeds received from the lessor that contractually constitutes payment to acquire the assets subject to these arrangements. Instead, the sale proceeds received are accounted for as financing obligations and leaseback payments made by the Company are allocated between interest expense and as a reduction to the financing obligation. Interest on the financing obligation is calculated using the Company’s incremental borrowing rate at the inception of the arrangement on the outstanding financing obligation. Judgment is required to determine the appropriate borrowing rate for the arrangement and in determining any gain or loss on the transaction that would be recorded either at the end of or over the lease term.
Marketing and Advertising Costs	Marketing and Advertising Costs The Company expenses its marketing and advertising costs as incurred and which are included within selling, general and administrative expenses. Marketing and advertising expenses for the years ended December 31, 2016, 2015, and 2014 were $247 million , $307 million , and $208 million , respectively. 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. Advertising expenses for the years ended December 31, 2016, 2015 and 2014 were $53 million , $135 million , and $87 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, the Company 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, 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. The reclassifications did not affect results from operations, net assets or cash flows.
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.
New Accounting Pronouncements, Policy [Policy Text Block]	Recent Accounting Developments ASU 2017-04 - In January 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350) , Simplifying the Test for Goodwill Impairment, or ASU No. 2017-04. The amendments of ASU No. 2017-04 aim at simplifying the subsequent measurement of goodwill. As a result, ASU No. 2017-04 eliminates Step 2 from the goodwill impairment test which previously required an entity to determine the fair value at the impairment testing date of the assets and liabilities following the procedures which would be required in determining the fair value of assets acquired and liabilities assumed under a business combination. Under ASU No. 2017-04, an entity shall perform its goodwill impairment test by comparing the fair value of the reporting unit with its carrying amount and recognize an impairment charge for the amount the carrying amount exceeds the reporting unit’s fair value. The amendments of ASU No. 2017-04 are effective for annual reporting periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017 and the adoption should be applied prospectively. ASU 2016-18 — In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230) , Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 were issued to address the diversity in classification and presentation of changes in restricted cash and restricted cash equivalents on the statement of cash flows which is currently not addressed under Topic 230. The amendments of ASU No. 2016-18 would require an entity to include amounts generally described as restricted cash and restricted cash equivalents with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted and the adoption of ASU No. 2016-18 should be applied retrospectively. The Company is currently evaluating the impact of the standard on the Company’s statement of cash flows. ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740) , Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16. The amendments of ASU No. 2016-16 were issued to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting. The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and do not require new disclosure requirements. The amendments of ASU No. 2016-16 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted and the adoption of ASU No. 2016-16 should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently evaluating the impact of the standard on the Company’s results of operations, cash flows and financial position. ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) , Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The amendments of ASU No. 2016-15 are effective for public entities for fiscal years beginning after December 15, 2017 and interim periods in those fiscal years. Early adoption is permitted, including adoption in an interim fiscal period with all amendments adopted in the same period. The adoption of ASU No. 2016-15 is required to be applied retrospectively. The Company is currently evaluating the impact of the standard on the Company's statement of cash flows. ASU 2016-09 — In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718), or ASU No. 2016-09. The amendments of ASU No. 2016-09 were issued as part of the FASB's Simplification Initiative focused on improving areas of GAAP for which cost and complexity may be reduced while maintaining or improving the usefulness of information disclosed within the financial statements. The amendments focused on simplification specifically with regard to share-based payment transactions, including income tax consequences, classification of awards as equity or liabilities and classification on the statement of cash flows. The guidance in ASU No. 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted this standard effective January 1, 2017. The adoption of this standard will not have a material impact on the Company's results of operations, cash flows and financial position. ASU 2016-07 — In March 2016, the FASB issued ASU No. 2016-07, Investments - Equity Method and Joint Ventures (Topic 323), or ASU No. 2016-07. The amendments of ASU No. 2016-07 eliminate the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The amendments require that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting with no retroactive adjustment to the investment. In addition, ASU No. 2016-07 requires that an entity that has an available-for-sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. The guidance in ASU No. 2016-07 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted this standard effective January 1, 2017. The adoption of ASU No. 2016-07 is required to be applied prospectively. The adoption of this standard will not have a material impact on the Company's results of operations, cash flows and financial position. ASU 2016-02 — In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842 with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. The Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts and service contracts which may contain embedded leases. As this review is still in process, it is currently not practicable to quantify the impact of adopting the ASU at this time. ASU 2016-01 — In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be generally measured at fair value with changes in fair value recognized in net income. Further, the amendments require that financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset. The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position. ASU 2015-16 — In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) : Simplifying the Accounting for Measurement-Period Adjustments , or ASU No. 2015-16. The amendments of ASU No. 2015-16 require that an acquirer recognize measurement period adjustments to the provisional amounts recognized in a business combination in the reporting period during which the adjustments are determined. Additionally, the amendments of ASU No. 2015-16 require the acquirer to record in the same period's financial statements the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the measurement period adjustment, calculated as if the accounting had been completed at the acquisition date as well as disclosing either on the face of the income statement or in the notes the portion of the amount recorded in current period earnings that would have been recorded in previous reporting periods. The guidance in ASU No. 2015-16 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied prospectively. The Company adopted ASU No. 2015-16 for the year ended December 31, 2016, and the adoption did not have a material impact on the Company's results of operations, cash flows and financial position. ASU 2014-15 — In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosures of Uncertainties about an Entity's Ability to Continue as a Going Concern , which requires management to evaluate whether there are conditions and events that raise substantial doubt about an entity's ability to continue as a going concern within one year after the financial statements are available to be issued. The Company adopted this ASU effective January 1, 2016. ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09, which was further amended through various updates issued by the FASB thereafter. The amendments of ASU No. 2014-09 completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes a five step model to be applied by an entity in evaluating its contracts with customers. The Company expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date by the entity. In 2016, the Company continued to assess the new standard with a focus on identifying the performance obligations included within its revenue arrangements with customers and evaluating the Company’s methods of estimating the amount and timing of variable consideration. Based on the assessment to date, the Company is currently evaluating the impact of the new standard on the Company’s results of operations, financial position or cash flows.
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 included in cost of operations and is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ( $90 million , $85 million and $86 million as of December 31, 2016 , 2015 , and 2014 , 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.

Summary of Significant Accoun39

Summary of Significant Accounting Policies Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Redeemable Noncontrolling Interest [Table Text Block]	The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2016 , 2015 , and 2014 . (In millions) Balance as of December 31, 2013 $ 2 Cash contributions from redeemable noncontrolling interest 36 Comprehensive loss attributable to redeemable noncontrolling interest (19 ) Balance as of December 31, 2014 19 Cash contributions from redeemable noncontrolling interest 27 Comprehensive loss attributable to redeemable noncontrolling interest (17 ) Balance as of December 31, 2015 29 Distributions to redeemable noncontrolling interest (1 ) Contributions from redeemable noncontrolling interest 56 Comprehensive loss attributable to redeemable noncontrolling interest (38 ) Balance as of December 31, 2016 $ 46

Business Acquisitions and Dis40

Business Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2016
Edison Mission Energy [Member]
Business Acquisition [Line Items]
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 December 31, 2014, as well as adjustments made through March 31, 2015, when the allocation became final. Measurement period adjustments primarily reflect the tax impact of the acquisition date fair values and final estimates for asset retirement obligations. The purchase price of $3.5 billion was allocated as follows: Acquisition Date Fair Value at December 31, 2014 Measurement period adjustments Revised Acquisition Date (In millions) Assets Cash $ 1,422 $ — $ 1,422 Current assets 724 72 796 Property, plant and equipment 2,438 (3 ) 2,435 Intangible assets 172 — 172 Goodwill 334 (56 ) 278 Non-current assets 773 — 773 Total assets acquired 5,863 13 5,876 Liabilities Current and non-current liabilities 629 13 642 Out-of-market contracts and leases 159 — 159 Long-term debt 1,249 — 1,249 Total liabilities assumed 2,037 13 2,050 Less: noncontrolling interest 352 — 352 Net assets acquired $ 3,474 $ — $ 3,474
Alta Wind Portfolio [Member]
Business Acquisition [Line Items]
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 December 31, 2014, as well as adjustments made through August 11, 2015, when the allocation became final. The purchase price of $923 million was allocated as follows: Acquisition Date Fair Value at December 31, 2014 Measurement period adjustments Revised Acquisition Date (In millions) Assets Cash $ 22 — $ 22 Current and non-current assets 49 (2 ) 47 Property, plant and equipment 1,304 6 1,310 Intangible assets 1,177 (6 ) 1,171 Total assets acquired 2,552 (2 ) 2,550 Liabilities Debt 1,591 — 1,591 Current and non-current liabilities 38 (2 ) 36 Total liabilities assumed 1,629 (2 ) 1,627 Net assets acquired $ 923 $ — $ 923

Fair Value of Financial Instr41

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value of Financial Instruments Disclosure [Abstract]
Fair Value Inputs, Assets, Quantitative Information [Table Text Block]	The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of December 31, 2016 and 2015: Significant Unobservable Inputs December 31, 2016 Fair Value Input/Range Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average (In millions) Power Contracts $ 40 $ 107 Discounted Cash Flow Forward Market Price (per MWh) $ 11 $ 104 $ 31 Coal Contracts — 1 Discounted Cash Flow Forward Market Price (per ton) 42 51 45 FTRs 52 53 Discounted Cash Flow Auction Prices (per MWh) (22 ) 17 — $ 92 $ 161 Significant Unobservable Inputs December 31, 2015 Fair Value Input/Range Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average (In millions) Power Contracts $ 86 $ 100 Discounted Cash Flow Forward Market Price (per MWh) $ 10 $ 92 $ 27 Coal Contracts — 12 Discounted Cash Flow Forward Market Price (per ton) 28 45 35 FTRs 63 70 Discounted Cash Flow Auction Prices (per MWh) (98 ) 87 — $ 149 $ 182
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 the Company's recorded financial instruments not carried at fair market value are as follows: As of December 31, 2016 2015 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Assets Notes receivable (a) $ 34 $ 34 $ 73 $ 73 Liabilities Long-term debt, including current portion (b) $ 19,406 $ 18,566 $ 19,620 $ 18,263 (a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets. (b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt 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. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of December 31, 2016 and 2015: As of December 31, 2016 As of December 31, 2015 Level 2 Level 3 Level 2 Level 3 (In millions) Long-term debt, including current portion $ 11,055 $ 7,511 $ 11,028 $ 7,235
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, 2016 Fair Value Level 1 Level 2 Level 3 Total (In millions) Investments in securities (classified within other non-current assets): Debt securities $ — $ — $ 17 $ 17 Available-for-sale securities 10 — — 10 Other (a) 10 — — 10 Nuclear trust fund investments: Cash and cash equivalents 25 — — 25 U.S. government and federal agency obligations 72 1 — 73 Federal agency mortgage-backed securities — 62 — 62 Commercial mortgage-backed securities — 17 — 17 Corporate debt securities — 84 — 84 Equity securities 292 — 54 346 Foreign government fixed income securities — 3 — 3 Other trust fund investments: U.S. government and federal agency obligations 1 — — 1 Derivative assets: Commodity contracts 559 551 92 1,202 Interest rate contracts — 49 — 49 Total assets $ 969 $ 767 $ 163 $ 1,899 Derivative liabilities: Commodity contracts $ 494 $ 635 $ 161 $ 1,290 Interest rate contracts — 88 — 88 Total liabilities $ 494 $ 723 $ 161 $ 1,378 (a) Consists primarily of mutual funds held in a rabbi trust for non-qualified deferred compensation plans for certain key and highly compensated employees and a total return swap that does not meet the definition of a derivative. As of December 31, 2015 Fair Value Level 1 Level 2 Level 3 Total (In millions) Investments in securities (classified within other non-current assets): Debt securities $ — $ — $ 17 $ 17 Available-for-sale securities 9 — — 9 Other (a) 14 — — 14 Nuclear trust fund investments: Cash and cash equivalents 6 — — 6 U.S. government and federal agency obligations 54 1 — 55 Federal agency mortgage-backed securities — 59 — 59 Commercial mortgage-backed securities — 25 — 25 Corporate debt securities — 81 — 81 Equity securities 280 — 54 334 Foreign government fixed income securities — 1 — 1 Other trust fund investments: U.S. government and federal agency obligations 1 — — 1 Derivative assets: Commodity contracts 622 1,449 149 2,220 Total assets $ 986 $ 1,616 $ 220 $ 2,822 Derivative liabilities: Commodity contracts $ 868 $ 1,036 $ 182 $ 2,086 Interest rate contracts — 128 — 128 Total liabilities $ 868 $ 1,164 $ 182 $ 2,214 (a) Primarily consists of mutual funds held in a rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative.
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, 2016 and 2015 , 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, 2016 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) Debt Securities Trust Fund Investments Derivatives (a) Total (In millions) Beginning balance as of January 1, 2016 $ 17 $ 54 $ (33 ) $ 38 Total gains/(losses) realized/unrealized: Included in earnings — — 12 12 Included in nuclear decommissioning obligations — (1 ) — (1 ) Purchases — 1 (29 ) (28 ) Transfers into Level 3 (b) — — (18 ) (18 ) Transfers out of Level 3 (b) — — (1 ) (1 ) Ending balance as of December 31, 2016 $ 17 $ 54 $ (69 ) $ 2 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, 2016 $ — $ — $ (14 ) $ (14 ) (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, 2015 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) Debt Securities Other Trust Fund Investments Derivatives (a) Total (In millions) Beginning balance as of January 1, 2015 $ 18 $ 11 $ 52 $ 80 $ 161 Total losses realized/unrealized: Included in earnings (1 ) (11 ) — (100 ) (112 ) Included in nuclear decommissioning obligations — — (2 ) — (2 ) Purchases — — 4 (19 ) (15 ) Transfers into Level 3 (b) — — — 3 3 Transfer out of Level 3 (b) — — — 3 3 Ending balance as of December 31, 2015 $ 17 $ — $ 54 $ (33 ) $ 38 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, 2015 $ — $ — $ — $ (30 ) $ (30 ) (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) (b) (% of Total) Utilities, energy merchants, marketers and other 100 Total 100 % Category Net Exposure (a) (b) (% of Total) Investment grade 67 % Non-Investment grade/Non-Rated 33 Total 100 % (a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices. (b) The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.
Fair Value Inputs, Sensitivity Analysis [Table Text Block]	The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2016 and 2015: Significant Unobservable Input Position Change In Input Impact on Fair Value Measurement Forward Market Price Power/Coal Buy Increase/(Decrease) Higher/(Lower) Forward Market Price Power/Coal Sell Increase/(Decrease) Lower/(Higher) FTR Prices Buy Increase/(Decrease) Higher/(Lower) FTR Prices Sell Increase/(Decrease) Lower/(Higher)

Accounting for Derivative Ins42

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 . 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, 2016 December 31, 2015 (In millions) Emissions Short Ton — 1 Coal Short Ton 41 35 Natural Gas MMBtu 85 293 Oil Barrel 1 1 Power MWh (28 ) (74 ) Capacity MW/Day (1 ) (1 ) Interest Dollars $ 3,429 $ 2,326 Equity Shares 1 1
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, 2016 December 31, 2015 December 31, 2016 December 31, 2015 Derivatives Designated as Cash Flow or Fair Value Hedges : Interest rate contracts current $ — $ — $ 28 $ 42 Interest rate contracts long-term 12 — 41 68 Total Derivatives Designated as Cash Flow or Fair Value Hedges 12 — 69 110 Derivatives Not Designated as Cash Flow or Fair Value Hedges : Interest rate contracts current — — 7 5 Interest rate contracts long-term 37 — 12 13 Commodity contracts current 1,062 1,915 1,049 1,674 Commodity contracts long-term 140 305 241 412 Total Derivatives Not Designated as Cash Flow or Fair Value Hedges 1,239 2,220 1,309 2,104 Total Derivatives $ 1,251 $ 2,220 $ 1,378 $ 2,214
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, 2016 (In millions) Commodity contracts: Derivative assets $ 1,202 $ (1,005 ) $ (1 ) $ 196 Derivative liabilities (1,290 ) 1,005 14 (271 ) Total commodity contracts (88 ) — 13 (75 ) Interest rate contracts: Derivative assets 49 (4 ) — 45 Derivative liabilities (88 ) 4 — (84 ) Total interest rate contracts (39 ) — — (39 ) Total derivative instruments $ (127 ) $ — $ 13 $ (114 ) 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, 2015 (In millions) Commodity contracts: Derivative assets $ 2,220 $ (1,616 ) $ (113 ) $ 491 Derivative liabilities (2,086 ) 1,616 271 (199 ) Total commodity contracts 134 — 158 292 Interest rate contracts: Derivative liabilities (128 ) — — (128 ) Total derivative instruments $ 6 $ — $ 158 $ 164
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, 2016 Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2015 $ (101 ) $ (101 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts 21 21 Mark-to-market of cash flow hedge accounting contracts 14 14 Accumulated OCI balance at December 31, 2016, net of $16 tax $ (66 ) $ (66 ) Losses expected to be realized from other comprehensive loss during the next 12 months, net of $4 tax $ (16 ) $ (16 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2016 . Year Ended December 31, 2015 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2014 $ (1 ) $ (67 ) $ (68 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts 1 14 15 Mark-to-market of cash flow hedge accounting contracts — (48 ) (48 ) Accumulated OCI balance at December 31, 2015, net of $16 tax $ — $ (101 ) $ (101 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2015 . Year Ended December 31, 2014 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2013 $ (1 ) $ (22 ) $ (23 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts — 13 13 Mark-to-market of cash flow hedge accounting contracts — (58 ) (58 ) Accumulated OCI balance at December 31, 2014, net of $35 tax $ (1 ) $ (67 ) $ (68 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2014 .
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 the Company'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, 2016 2015 2014 (In millions) Unrealized mark-to-market results Reversal of previously recognized unrealized gains on settled positions related to economic hedges $ (245 ) $ (275 ) $ (15 ) Reversal of acquired gain positions related to economic hedges (60 ) (106 ) (333 ) Net unrealized gains on open positions related to economic hedges 20 9 361 Total unrealized mark-to-market (losses)/gains for economic hedging activities (285 ) (372 ) 13 Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity 10 (46 ) 1 Reversal of acquired gain positions related to trading activity — (14 ) (32 ) Net unrealized gains/(losses) on open positions related to trading activity 18 (16 ) 45 Total unrealized mark-to-market gains/(losses) for trading activity 28 (76 ) 14 Total unrealized (losses)/gains $ (257 ) $ (448 ) $ 27 Year Ended December 31, 2016 2015 2014 (In millions) Unrealized (losses)/gains included in operating revenues $ (837 ) $ (320 ) $ 515 Unrealized gains/(losses) included in cost of operations 580 (128 ) (488 ) Total impact to statement of operations — energy commodities $ (257 ) $ (448 ) $ 27 Total impact to statement of operations — interest rate contracts $ 36 $ 17 $ (31 )

Nuclear Decommissioning Trust43

Nuclear Decommissioning Trust Fund (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 As of December 31, 2015 (In millions, except otherwise noted) Fair Value Unrealized Gains Unrealized Losses Weighted- average maturities (in years) Fair Value Unrealized Gains Unrealized Losses Weighted- average maturities (in years) Cash and cash equivalents $ 25 $ — $ — — $ 6 $ — $ — — U.S. government and federal agency obligations 73 1 — 11 55 1 — 11 Federal agency mortgage-backed securities 62 1 1 25 59 1 — 25 Commercial mortgage-backed securities 17 — 1 26 25 — 2 28 Corporate debt securities 84 1 2 11 81 1 1 10 Equity securities 346 214 — — 334 199 — — Foreign government fixed income securities 3 — — 9 1 — — 9 Total $ 610 $ 217 $ 4 $ 561 $ 202 $ 3
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 using the specific identification method. Year Ended December 31, 2016 2015 2014 (In millions) Realized gains $ 26 $ 21 $ 29 Realized losses 11 14 8 Proceeds from sale of securities 510 631 600

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Schedule of Inventory	Inventory consisted of: As of December 31, 2016 2015 (In millions) Fuel oil $ 289 $ 312 Coal/Lignite 334 471 Natural gas 28 12 Spare parts 413 437 Other 47 20 Total Inventory $ 1,111 $ 1,252

Notes Receivable (Tables)

Notes Receivable (Tables)	12 Months Ended
	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Schedule of NRG's notes receivable and capital leases	's notes receivable were as follows: As of December 31, 2016 2015 (In millions) Notes receivable $ 34 $ 73 Less current maturities (a) 17 20 Total notes receivable — non-current $ 17 $ 53 (a) The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

Property, Plant and Equipment46

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
NRG's major classes of property, plant and equipment	The Company's major classes of property, plant, and equipment were as follows: As of December 31, Depreciable 2016 2015 Lives (In millions) Facilities and equipment $ 21,445 $ 21,633 1-40 Years Land and improvements 1,026 1,226 Nuclear fuel 601 545 5 Years Office furnishings and equipment 457 462 2-10 Years Construction in progress 697 627 Total property, plant, and equipment 24,226 24,493 Accumulated depreciation (6,314 ) (5,761 ) Net property, plant, and equipment $ 17,912 $ 18,732

Goodwill an Other Intangibles (

Goodwill an Other Intangibles (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) January 1, 2016 $ 920 $ 54 $ 72 $ 16 $ 834 $ 88 $ 342 $ 1,264 $ 245 $ 3,835 Purchases 50 — — — — — — — 34 84 Acquisition of businesses — — — — — — — — 18 18 Usage (1 ) — — — — — — — (44 ) (45 ) Write-off of fully amortized balances (a) (10 ) — — — — — — — — (10 ) Impairment (b) (23 ) — — — (18 ) — — — (23 ) (64 ) Other (7 ) — — — — — — — — (7 ) December 31, 2016 929 54 72 16 816 88 342 1,264 230 3,811 Less accumulated amortization (605 ) (54 ) (67 ) (8 ) (663 ) (49 ) (159 ) (138 ) (32 ) (1,775 ) Net carrying amount $ 324 $ — $ 5 $ 8 $ 153 $ 39 $ 183 $ 1,126 $ 198 $ 2,036 (a) Adjusted for write-off of fully amortized emission allowances of $10 million . (b) The impairment of customer relationships and other intangibles included a write-off of accumulated amortization of $10 million and $8 million respectively. Contracts Year Ended December 31, 2015 Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) January 1, 2015 $ 1,018 $ 54 $ 72 $ 16 $ 831 $ 88 $ 353 $ 1,270 $ 267 $ 3,969 Purchases 77 — — — 3 — — — 57 137 Usage (33 ) — — — — — — — (62 ) (95 ) Write-off of fully amortized balances (154 ) — — — — — — — — (154 ) Impairment — — — — — — (6 ) — (5 ) (11 ) Other 12 — — — — — (5 ) (6 ) (12 ) (11 ) December 31, 2015 920 54 72 16 834 88 342 1,264 245 3,835 Less accumulated amortization (a) (502 ) (47 ) (65 ) (6 ) (624 ) (41 ) (137 ) (75 ) (28 ) (1,525 ) Net carrying amount $ 418 $ 7 $ 7 $ 10 $ 210 $ 47 $ 205 $ 1,189 $ 217 $ 2,310 (a) Adjusted for write-off of fully amortized emission allowances of $154 million .
Finite-lived Intangible Assets Amortization Expense [Table Text Block]	The following table presents NRG's amortization of intangible assets for each of the past three years: Years Ended December 31, Amortization 2016 2015 2014 (In millions) Emission allowances $ 113 $ 99 $ 124 Energy supply contracts 7 5 6 Fuel contracts 2 2 2 Customer contracts 2 2 — Customer relationships 49 67 70 Marketing partnerships 8 14 15 Trade names 22 23 21 Power purchase agreements 63 50 24 Other 12 15 6 Total amortization $ 278 $ 277 $ 268
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 Allowances Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) 2017 $ 82 $ 1 $ 1 $ 26 $ 5 $ 23 $ 57 $ 3 $ 198 2018 33 — 1 14 5 23 57 3 136 2019 31 — 1 10 4 23 57 3 129 2020 16 — 1 8 4 23 57 3 112 2021 16 — 1 6 4 23 57 3 110
Schedule of Out of Market Contracts, Future Amortization [Table Text Block]	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) 2017 $ 16 47 $ 37 $ 100 2018 16 47 32 95 2019 17 47 29 93 2020 17 47 29 93 2021 10 47 26 83

Debt and Capital Leases (Tables

Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Instrument
Long-term debt and capital leases	Long-term debt and capital leases consisted of the following: As of December 31, December 31, 2016 2016 2015 Interest Rate % (a) (In millions except rates) NRG Recourse Debt: Senior notes, due 2018 $ 398 $ 1,039 7.625 Senior notes, due 2020 — 1,058 8.250 Senior notes, due 2021 207 1,128 7.875 Senior notes, due 2022 992 1,100 6.250 Senior notes, due 2023 869 936 6.625 Senior notes, due 2024 733 904 6.250 Senior notes, due 2026 1,000 — 7.250 Senior notes, due 2027 1,250 — 6.625 Term loan facility, due 2018 — 1,964 L+2.00 Term loan facility, due 2023 1,882 — L+2.75 Tax-exempt Bonds 455 455 4.125 - 6.00 Subtotal NRG Recourse Debt 7,786 8,584 NRG Non-Recourse Debt: GenOn senior notes 1,911 1,956 7.875 - 9.875 GenOn Americas Generation senior notes 745 752 8.500 - 9.125 GenOn Other 96 56 Subtotal GenOn debt (non-recourse to NRG) 2,752 2,764 NRG Yield Operating LLC Senior Notes, due 2024 500 500 5.375 NRG Yield Operating LLC Senior Notes, due 2026 350 — 5.000 NRG Yield LLC and Yield Operating LLC Revolving Credit Facility, due 2019 — 306 L+2.75 NRG Yield Inc. Convertible Senior Notes, due 2019 335 330 3.500 NRG Yield Inc. Convertible Senior Notes, due 2020 271 266 3.250 El Segundo Energy Center, due 2023 443 485 L+1.625 - L+2.25 Marsh Landing, due 2017 and 2023 370 418 L+1.75 - L+1.875 Alta Wind I-V lease financing arrangements, due 2034 and 2035 965 1,002 5.696 - 7.015 Walnut Creek, term loans due 2023 310 351 L+1.625 Tapestry, due 2021 172 181 L+1.625 CVSR, due 2037 771 793 2.339 - 3.775 CVSR HoldCo, due 2037 199 — 4.680 Alpine, due 2022 145 154 L+1.750 Energy Center Minneapolis, due 2017 and 2025 96 108 5.95 - 7.25 Energy Center Minneapolis, due 2031 125 — 3.55 Viento, due 2023 178 189 L+2.75 NRG Yield - other 540 573 various Subtotal NRG Yield debt (non-recourse to NRG) 5,770 5,656 Ivanpah, due 2033 and 2038 1,113 1,149 2.285 - 4.256 Agua Caliente, due 2037 849 879 2.395 - 3.633 Dandan, due 2033 76 98 L+2.25 Peaker bonds, due 2019 — 72 L+1.07 Cedro Hill, due 2025 163 103 L+1.75 Utah Portfolio, due 2022 287 — L+2.65 Midwest Generation, due 2019 218 — 4.390 NRG Other 392 315 various Subtotal other NRG non-recourse debt 3,098 2,616 Subtotal all non-recourse debt 11,620 11,036 Subtotal long-term debt (including current maturities) 19,406 19,620 Capital leases: 8 16 various Subtotal long-term debt and capital leases (including current maturities) 19,414 19,636 Less current maturities 1,220 481 Less debt issuance costs 188 172 Total long-term debt and capital leases $ 18,006 $ 18,983 (a) As of December 31, 2016 , L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%. Long-term debt includes the following premiums/(discounts): As of December 31, 2016 2015 (In millions) Term loan facility, due 2018 (a) $ — $ (3 ) Term loan facility, due 2023 (a) (9 ) — Peaker bonds, due 2019 (b) — (4 ) Yield, Inc. Convertible notes, due 2019 (10 ) (15 ) Yield, Inc. Convertible notes, due 2020 (17 ) (21 ) Midwest Generation, due 2019 (13 ) — GenOn senior notes, due 2017 (c) 8 23 GenOn senior notes, due 2018 (c) 38 59 GenOn senior notes, due 2020 (c) 35 44 GenOn Americas Generation senior notes, due 2021 (c) 26 32 GenOn Americas Generation senior notes, due 2031 (c) 24 25 Total premium $ 82 $ 140 (a) Term loan facility, due 2018 replaced with the Term loan facility due 2023. Discount of $1 million was related to current maturities in 2016. (b) Repaid in 2016. (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.
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, 2016 . % of Principal Fixed Interest Rate Floating Interest Rate Notional Amount at December 31, 2016 (In millions) Effective Date Maturity Date Recourse Debt NRG Energy 85 % various 1-mo. LIBOR $ 1,000 June 30, 2016 June 30, 2021 Non-Recourse Debt El Segundo Energy Center 75 % 2.417 % 3-mo. LIBOR 330 November 30, 2011 August 31, 2023 South Trent Wind LLC 75 % 3.265 % 3-mo. LIBOR 43 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 28 September 30, 2011 December 31, 2029 NRG Solar Alpine LLC 85 % 2.744 % 3-mo. LIBOR 115 various December 31, 2029 NRG Solar Alpine LLC 85 % 2.421 % 3-mo. LIBOR 8 June 24, 2014 June 30, 2025 NRG Solar Avra Valley LLC 85 % 2.333 % 3-mo. LIBOR 49 November 30, 2012 November 30, 2030 NRG Marsh Landing 75 % 3.244 % 3-mo. LIBOR 342 June 28, 2013 June 30, 2023 Iron Springs 80 % 2.555 % 1-mo. LIBOR 34 December 15, 2016 September 30, 2036 Four Brothers 80 % 2.567 % 1-mo. LIBOR 141 December 15, 2016 September 30, 2036 Granite Mountain 80 % 2.557 % 1-mo. LIBOR 56 December 15, 2016 September 30, 2036 DGPV 4 85 % various 3-mo. LIBOR 19 various various Other 75 % various various 142 various various EME Project Financings Broken Bow 75 % various 3-mo. LIBOR 58 various various Cedro Hill 90 % various 3-mo. LIBOR 147 various various Crofton Bluffs 75 % various 3-mo. LIBOR 38 various various Laredo Ridge 75 % 2.310 % 3-mo. LIBOR 79 March 31, 2011 March 31, 2026 Tapestry 75 % 2.210 % 3-mo. LIBOR 155 December 30, 2011 December 21, 2021 Tapestry 50 % 3.570 % 3-mo. LIBOR 60 December 21, 2021 December 21, 2029 Viento Funding II 90 % various 6-mo. LIBOR 160 various various Viento Funding II 90 % 4.985 % 6-mo. LIBOR 65 July 11, 2023 June 30, 2028 Walnut Creek Energy 75 % various 3-mo. LIBOR 276 June 28, 2013 May 31, 2023 WCEP Holdings 90 % 4.003 % 3-mo. LIBOR 46 June 28, 2013 May 21, 2023 Alta Wind Project Financings AWAM 100 % 2.470 % 3-mo. LIBOR 18 May 22, 2013 May 15, 2031 Total $ 3,430
Annual payments based on the maturities of NRG's debt	Annual payments based on the maturities of NRG's debt and capital leases for the years ending after December 31, 2016 are as follows: (In millions) 2017 $ 1,222 2018 1,650 2019 839 2020 1,273 2021 1,157 Thereafter 13,192 Total $ 19,333
GenOn Americas Generation senior notes
Debt Instrument
Schedule of Long-term Debt Instruments [Table Text Block]	As of December 31, 2016 2015 Interest Rate % Amount in millions, except rates Senior unsecured notes, due 2021 $ 392 $ 398 8.500 Senior unsecured notes, due 2031 353 354 9.125 Total $ 745 $ 752
Debt Instrument Redemption [Table Text Block]	During the fourth quarter of 2015, the Company repurchased $155 million in aggregate principal of the following outstanding Senior Notes for $128 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain on Debt Extinguishment Amount in millions, except rates Senior unsecured notes, due 2021 $ 84 84.910 % $ 20 Senior unsecured notes, due 2031 71 77.018 % 22 Total $ 155 $ 42
Tax-exempt Bonds
Debt Instrument
Schedule of Long-term Debt Instruments [Table Text Block]	Tax Exempt Bonds As of December 31, 2016 2015 Interest Rate % Amount in millions, except rates Indian River Power tax exempt bonds, due 2040 $ 57 $ 57 6.000 Indian River Power LLC, tax exempt bonds, due 2045 190 190 5.375 Dunkirk Power LLC, tax exempt bonds, due 2042 59 59 5.875 City of Texas City, tax exempt bonds, due 2045 22 22 4.125 Fort Bend County, tax exempt bonds, due 2038 54 54 4.750 Fort Bend County, tax exempt bonds, due 2042 73 73 4.750 Total $ 455 $ 455
Senior Notes [Member]
Debt Instrument
Debt Instrument Redemption [Table Text Block]	Principal Repurchased Cash Paid (a) Average Early Redemption Percentage Amount in millions, except rates 7.625% senior notes due 2018 (b) $ 641 $ 706 107.89 % 8.250% senior notes due 2020 1,058 1,129 103.12 % 7.875% senior notes due 2021 (c) 922 978 104.00 % 6.250% senior notes due 2022 108 105 94.73 % 6.625% senior notes due 2023 67 64 94.13 % 6.250% senior notes due 2024 171 163 94.52 % Total $ 2,967 $ 3,145 (a) Includes payment for accrued interest. (b) $186 million of the redemptions financed by cash on hand. (c) $193 million of the redemptions financed by cash on hand. 2015 Senior Notes Repurchases During the year ended December 31, 2015, the Company repurchased $246 million in aggregate principal of its Senior Notes for $231 million , which included accrued interest of $5 million . In connection with the repurchases, a $19 million gain on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $2 million . Principal Repurchased Cash Paid (a) Average Early Redemption Percentage Amount in millions, except rates 7.625% senior notes due 2018 $ 92 $ 97 102.23 % 8.250% senior notes due 2020 5 5 96.50 % 6.625% senior notes due 2023 54 47 85.97 % 6.250% senior notes due 2024 95 82 84.73 % Total $ 246 $ 231 (a) Includes payment for accrued interest.
Senior notes, due 2021
Debt Instrument
Debt Instrument Redemption [Table Text Block]	2021 Senior Notes 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 100.000 %
Senior notes, due 2023
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after September 15, 2017, NRG may redeem some or all of the 2023 Senior 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 100.000 %
GenOn senior notes, due 2020
Debt Instrument
Debt Instrument Redemption [Table Text Block]	GenOn may redeem some or all of the Senior Notes due 2020 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, 2016 to October 14, 2017 103.292 % October 15, 2017 to October 14, 2018 101.646 % October 15, 2018 and thereafter 100.000 %
Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after July 15, 2018, 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 July 15, 2018 to July 14, 2019 103.125 % July 15, 2019 to July 14, 2020 101.563 % July 15, 2020 and thereafter 100.000 %
Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after May 1, 2019, 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 1, 2019 to April 30, 2020 103.125 % May 1, 2020 to April 30, 2021 102.083 % May 1, 2021 to April 30, 2022 101.042 % May 1, 2022 and thereafter 100.000 %
GenOn Senior Notes [Member]
Debt Instrument
Schedule of Long-term Debt Instruments [Table Text Block]	As of December 31, 2016 2015 Interest Rate % Amount in millions, except rates Senior unsecured notes, due 2017 $ 699 $ 714 7.875 Senior unsecured notes, due 2018 687 708 9.500 Senior unsecured notes, due 2020 525 534 9.875 Total $ 1,911 $ 1,956
Debt Instrument Redemption [Table Text Block]	During the fourth quarter of 2015, the Company repurchased $119 million in aggregate principal of the following outstanding Senior Notes for $108 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain on Debt Extinguishment Amount in millions, except rates Senior unsecured notes, due 2017 $ 33 95.172 % $ 3 Senior unsecured notes, due 2018 25 90.950 % 5 Senior unsecured notes, due 2020 61 83.847 % 15 Total $ 119 $ 23
Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after May 15, 2021, 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, 2021 to May 14, 2022 103.625 % May 15, 2022 to May 14, 2023 102.417 % May 15, 2023 to May 14, 2024 101.208 % May 15, 2024 and thereafter 100.000 %
Senior Notes due 2027 [Member]
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after July 15, 2021, 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 July 15, 2021 to July14, 2022 103.313 % July 15, 2022 to July 14, 2023 102.208 % July 15, 2023 to July 14, 2024 101.104 % July 15, 2024 and thereafter 100.000 %
Leasing Arrangement [Member]
Debt Instrument
Schedule of Project level debt assumed during acquisition [Table Text Block]	Amount in millions, except rates Lease Financing Arrangement Letter of Credit Facility Non-Recourse Debt Amount Outstanding as of December 31, 2016 Interest Rate Maturity Date Amount Outstanding as of December 31, 2016 Interest Rate Maturity Date Alta Wind I $ 242 7.015% 12/30/2034 $ 16 3.250% 1/5/2021 Alta Wind II 191 5.696% 12/30/2034 27 2.750% 6/30/2017& 12/31/2017 Alta Wind III 198 6.067% 12/30/2034 27 2.750% various Alta Wind IV 128 5.938% 12/30/2034 19 2.750% various Alta Wind V 206 6.071% 6/30/2035 30 2.750% various Total $ 965 $ 119

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 , along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2016 : (In millions) Balance as of December 31, 2015 $ 945 Revisions in estimates for current obligations (103 ) Additions 49 Spending for current obligations (8 ) Accretion — Expense 42 Accretion — Nuclear decommissioning 15 Balance as of December 31, 2016 $ 940

Benefit Plans and Other Postr50

Benefit Plans and Other Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Annual net periodic benefit cost related to NRG's pension and other postretirement benefit plans	The annual net periodic benefit cost/(credit) related to NRG's pension and other postretirement benefit plans include the following components: Year Ended December 31, Pension Benefits 2016 2015 2014 (In millions) Service cost benefits earned $ 30 $ 32 $ 30 Interest cost on benefit obligation 43 53 53 Expected return on plan assets (60 ) (62 ) (62 ) Amortization of unrecognized net loss/(gain) 2 2 (6 ) Net periodic benefit cost $ 15 $ 25 $ 15 Year Ended December 31, Other Postretirement Benefits 2016 2015 2014 (In millions) Service cost benefits earned $ 2 $ 3 $ 3 Interest cost on benefit obligation 6 9 9 Amortization of unrecognized prior service credit (5 ) (5 ) (17 ) Amortization of unrecognized net loss — 1 — Curtailment gain — (14 ) — Net periodic benefit cost/(credit) $ 3 $ (6 ) $ (5 )
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 2016 2015 2016 2015 (In millions) Benefit obligation at January 1 $ 1,196 $ 1,305 $ 178 $ 238 Service cost 30 32 2 3 Interest cost 43 53 6 9 Plan amendments — — (42 ) (6 ) Actuarial loss/(gain) 40 (120 ) (2 ) (31 ) Employee and retiree contributions — — 3 2 Benefit payments (68 ) (74 ) (17 ) (12 ) Curtailment — — — (25 ) Benefit obligation at December 31 1,241 1,196 128 178 Fair value of plan assets at January 1 916 988 — — Actual return on plan assets 72 (26 ) — — Employee and retiree contributions — — 3 2 Employer contributions 33 28 14 10 Benefit payments (68 ) (74 ) (17 ) (12 ) Fair value of plan assets at December 31 953 916 — — Funded status at December 31 — excess of obligation over assets $ (288 ) $ (280 ) $ (128 ) $ (178 )
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 2016 2015 2016 2015 (In millions) Current liabilities $ — $ — $ 8 $ 12 Non-current liabilities 288 280 120 166
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 2016 2015 2016 2015 (In millions) Net loss/(gain) $ 94 $ 68 $ (11 ) $ (9 ) Prior service cost/(credit) 3 3 (45 ) (9 )
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 Benefits Other Postretirement Benefits 2016 2015 2016 2015 (In millions) Net actuarial loss/(gain) $ 28 $ (31 ) $ (2 ) $ (31 ) Amortization of net actuarial (gain)/loss (2 ) (2 ) — (1 ) Prior service credit — (1 ) (41 ) (7 ) Amortization of prior service cost — — 5 5 Curtailment — — — (11 ) Total recognized in other comprehensive loss/(income) $ 26 $ (34 ) $ (38 ) $ (45 ) Total recognized in net periodic pension cost/(credit) and other comprehensive loss/(income) $ 41 $ (8 ) $ 36 $ (37 )
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 2016 2015 (In millions) Projected benefit obligation $ 1,241 $ 1,196 Accumulated benefit obligation 1,174 1,115 Fair value of plan assets 953 916
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, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total (In millions) Common/collective trust investment — U.S. equity $ — $ 283 $ 283 Common/collective trust investment — non-U.S. equity — 149 149 Common/collective trust investment — global equity — 104 104 Common/collective trust investment — fixed income — 383 383 Partnerships/joint ventures — 31 31 Short-term investment fund 3 — 3 Total $ 3 $ 950 $ 953 Fair Value Measurements as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total (In millions) Common/collective trust investment — U.S. equity $ — $ 255 $ 255 Common/collective trust investment — non-U.S. equity — 147 147 Common/collective trust investment — global equity — 90 90 Common/collective trust investment — fixed income — 400 400 Partnerships/joint ventures — 18 18 Short-term investment fund 6 — 6 Total $ 6 $ 910 $ 916
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 2016 2015 2016 2015 Discount rate 4.26 % 4.52 % 4.29 % 4.55 % Rate of compensation increase 3.00 % 3.00 % N/A N/A Health care trend rate — — 7.0% grading to 5.0% in 2025 7.25% grading to 5.0% in 2025 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 2016 2015 2014 2016 2015 2014 Discount rate 4.52 % 4.16 % 4.99 % 4.55 % 4.20 % 5.06 % Expected return on plan assets 6.65 % 6.36 % 6.81 % — — — Rate of compensation increase 3.00 % 3.45 % 3.65 % — — — Health care trend rate — — — 7.25% grading to 5.0% in 2025 8.6% grading to 5.0% in 2023 8.5% grading to 5.5% in 2019
Target allocations of NRG's pension plan assets	The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2016 : U.S. equity 27 % Non-U.S. equity 15 % Global equity 10 % Emerging market equity 3 % U.S. fixed income 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 Benefit Payments Medicare Prescription Drug Reimbursements (In millions) 2017 $ 66 $ 8 $ — 2018 69 8 — 2019 72 8 — 2020 76 9 — 2021 79 9 — 2022-2026 417 38 1
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- Point Increase 1-Percentage- Point Decrease (In millions) Effect on total service and interest cost components $ 1 $ — Effect on postretirement benefit obligation 9 (8 )
Contributions to defined contribution plans	The Company's contributions to these plans were as follows: Year Ended December 31, 2016 2015 2014 (In millions) Company contributions to defined contribution plans $ 55 $ 53 $ 47
South Texas Project Units 1 And 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
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 2016 2015 2016 2015 (In millions) Funded status — STPNOC benefit plans $ (74 ) $ (63 ) $ (23 ) $ (26 ) Net periodic benefit cost/(credit) 7 10 (2 ) (8 ) Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss) 11 (8 ) (1 ) 6

Capital Structure (Tables)

Capital Structure (Tables)	12 Months Ended
	Dec. 31, 2016
Preferred Units [Line Items]
Class of Treasury Stock [Table Text Block]	Share Repurchases — During 2015 and 2014, the Company's board of directors authorized share repurchases of $481 million of its common stock, which were made as follows: Total number of shares purchased Average price paid per share (a) Amounts paid for shares purchased (in millions) (a) Board Authorized Share Repurchases Fourth Quarter 2014 1,624,360 $ 26.95 $ 44 First Quarter 2015 3,146,484 25.15 79 Second Quarter 2015 4,379,907 24.53 107 Third Quarter 2015 11,104,184 15.06 167 Fourth Quarter 2015 5,558,920 15.03 84 Total Board Authorized Share Repurchases 25,813,855 $ 481 (a) The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.015 per share paid in connection with the share repurchase.
Temporary Equity [Table Text Block]	The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended December 31, 2016 , 2015 , and 2014: (In millions) Balance as of December 31, 2013 $ 249 Loss recorded in connection with extinguishment of 3.625% preferred stock and issuance of 2.822% preferred stock 42 Balance as of December 31, 2014 291 Accretion to redemption value 11 Balance as of December 31, 2015 302 Accretion to redemption value 2 Repurchase of 2.822% redeemable preferred stock (226 ) Gain on redemption of 2.822% redeemable preferred stock (78 ) Balance as of December 31, 2016 $ —
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, 2013 401,126,780 (77,347,528 ) 323,779,252 Shares issued under ESPP — 128,336 128,336 Shares issued under LTIPs 1,707,419 — 1,707,419 Shares issued in connection with the EME acquisition 12,671,977 — 12,671,977 Share repurchases — (1,624,360 ) (1,624,360 ) Balance as of December 31, 2014 415,506,176 (78,843,552 ) 336,662,624 Shares issued under ESPP — 283,139 283,139 Shares issued under LTIPs 1,433,774 — 1,433,774 Share repurchases — (24,189,495 ) (24,189,495 ) Balance as of December 31, 2015 416,939,950 (102,749,908 ) 314,190,042 Shares issued under ESPP — 609,094 609,094 Shares issued under LTIPs 643,875 — 643,875 Balance as of December 31, 2016 417,583,825 (102,140,814 ) 315,443,011
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 the long-term incentive plans as of December 31, 2016 : Equity Instrument Common Stock Reserve Balance Long-term incentive plans 17,336,092
Dividends paid per common share	The following table lists the dividends paid per common share during 2016 , 2015 and 2014 : Fourth Quarter Third Quarter Second Quarter First Quarter 2016 $ 0.030 $ 0.030 $ 0.030 $ 0.145 2015 $ 0.145 $ 0.145 $ 0.145 $ 0.145 2014 $ 0.140 $ 0.140 $ 0.140 $ 0.120

Investments Accounted for by 52

Investments Accounted for by the Equity Method and Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Additional Financial Information Disclosure [Text Block]	The summarized financial information for the Company's consolidated VIEs consisted of the following: (In millions) December 31, 2016 December 31, 2015 Current assets $ 87 $ 84 Net property, plant and equipment 1,534 1,807 Other long-term assets 954 863 Total assets 2,575 2,754 Current liabilities 59 56 Long-term debt 442 366 Other long-term liabilities 183 179 Total liabilities 684 601 Noncontrolling interests 529 493 Net assets less noncontrolling interests $ 1,362 $ 1,660
Undistributed earnings by equity investment	As of December 31, 2016 2015 (In millions) Undistributed earnings from equity investments $ 101 $ 55
Summary NRG's equity method investments	The following table summarizes NRG's equity method investments as of December 31, 2016 : Name Economic Interest Investment Balance (In millions) Avenal Solar Holdings LLC (a) 50.0 % $ (7 ) Community Wind North, LLC 99.0 % 21 Desert Sunlight Investment Holdings, LLC (a) 25.0 % 282 Elkhorn Ridge Wind, LLC (a) 47.0 % 85 GenConn Energy LLC (a) 50.0 % 106 Four Brothers Holdings (c) 50.0 % 208 Granite Mountain Renewables (c) 50.0 % 90 Iron Springs Renewables (c) 50.0 % 48 Midway-Sunset Cogeneration Company 50.0 % 22 Petra Nova Parish Holdings LLC 50.0 % 34 Saguaro Power Company 50.0 % (14 ) San Juan Mesa Wind Project, LLC (a) 75.0 % 74 Sherbino I Wind Farm LLC 50.0 % — Watson Cogeneration Company 49.0 % 26 Gladstone Power Station (b) 37.5 % 132 Other Various 13 Total equity investments in affiliates $ 1,120 (a) Equity method investments owned by NRG Yield (b) Gladstone Power Station is located in Australia

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment reporting information	For the Year Ended December 31, 2016 Generation (a) Retail (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 5,679 $ 6,336 $ 417 $ 1,021 $ 77 $ (1,179 ) $ 12,351 Operating expenses 4,922 5,169 215 322 212 (1,184 ) 9,656 Depreciation and amortization 702 115 190 297 63 — 1,367 Impairment losses 645 1 56 183 33 — 918 Acquisition-related transaction and integration costs — — — 1 7 — 8 Development costs 22 4 40 — 24 — 90 Total operating cost and expenses 6,291 5,289 501 803 339 (1,184 ) 12,039 Gain/(loss) on sale of assets 294 (1 ) — — (78 ) — 215 Operating (loss)/income (318 ) 1,046 (84 ) 218 (340 ) 5 527 Equity in (losses)/earnings of unconsolidated affiliates (5 ) — (30 ) 37 7 18 27 Impairment losses on investments (142 ) — (105 ) — (21 ) — (268 ) Other income, net 36 1 1 3 62 (61 ) 42 Loss on debt extinguishment — — — — (142 ) — (142 ) Interest expense (79 ) (1 ) (108 ) (274 ) (658 ) 59 (1,061 ) (Loss)/income before income taxes (508 ) 1,046 (326 ) (16 ) (1,092 ) 21 (875 ) Income tax (benefit)/expense (1 ) 1 (20 ) (1 ) 37 — 16 Net (loss)/income $ (507 ) $ 1,045 $ (306 ) $ (15 ) $ (1,129 ) $ 21 $ (891 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — — (13 ) (54 ) 16 (66 ) (117 ) Net (loss)/income attributable to NRG Energy, Inc. $ (507 ) $ 1,045 $ (293 ) $ 39 $ (1,145 ) $ 87 $ (774 ) Balance sheet Equity investments in affiliates $ 204 $ — $ 372 $ 710 $ 91 $ (257 ) $ 1,120 Capital expenditures (b) 767 12 330 23 110 — 1,242 Goodwill 199 340 12 111 662 Total assets $ 13,256 $ 1,977 $ 5,280 $ 8,383 $ 15,590 $ (14,131 ) $ 30,355 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 955 $ 4 $ 23 $ 8 $ 189 $ — $ 1,179 (b) Includes accruals. For the Year Ended December 31, 2015 Generation (a) Retail (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 7,546 $ 6,914 $ 392 $ 953 $ 39 $ (1,170 ) $ 14,674 Operating expenses 6,210 6,113 185 333 291 (1,149 ) 11,983 Depreciation and amortization 896 133 181 297 59 — 1,566 Impairment losses 4,827 36 13 — 132 22 5,030 Acquisition-related transaction and integration costs — 1 — 3 6 — 10 Development costs 27 4 52 — 63 — 146 Total operating cost and expenses 11,960 6,287 431 633 551 (1,127 ) 18,735 Gain on postretirement benefits curtailment 21 — — — — — 21 Operating (loss)/income (4,393 ) 627 (39 ) 320 (512 ) (43 ) (4,040 ) Equity in earnings/(losses) of unconsolidated affiliates 10 — 9 26 — (9 ) 36 Impairment losses on investments (14 ) — — — (42 ) — (56 ) Other income, net 48 (1 ) 3 3 78 (98 ) 33 (Loss)/gain on debt extinguishment — — — (9 ) 84 — 75 Loss on sale of equity method investment — — — — (14 ) — (14 ) Interest expense (97 ) (1 ) (83 ) (263 ) (779 ) 95 (1,128 ) (Loss)/income before income taxes (4,446 ) 625 (110 ) 77 (1,185 ) (55 ) (5,094 ) Income tax expense/(benefit) — 1 (18 ) 12 1,347 — 1,342 Net (loss)/income (4,446 ) 624 (92 ) 65 (2,532 ) (55 ) (6,436 ) Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests — — 6 19 (37 ) (42 ) (54 ) Net (loss)/income attributable to NRG Energy, Inc. $ (4,446 ) $ 624 $ (98 ) $ 46 $ (2,495 ) $ (13 ) $ (6,382 ) Balance sheet Equity investments in affiliates $ 334 $ — $ 134 $ 697 $ 127 $ (247 ) $ 1,045 Capital expenditures (b) 792 36 163 30 246 — 1,267 Goodwill 536 340 12 — 111 — 999 Total assets $ 17,625 $ 2,017 $ 5,142 $ 8,689 $ 19,720 $ (20,311 ) $ 32,882 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 898 $ 6 $ 25 $ 29 $ 212 $ — $ 1,170 (b) Includes accruals. For the Year Ended December 31, 2014 Generation (a) Retail (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 9,288 $ 7,393 $ 344 $ 828 $ 19 $ (2,004 ) $ 15,868 Operating expenses 6,985 7,270 191 285 151 (2,058 ) 12,824 Depreciation and amortization 957 134 164 233 35 — 1,523 Impairment losses 87 — 32 — (22 ) — 97 Acquisition-related transaction and integration costs 1 3 — 4 76 — 84 Development costs 12 1 40 — 35 — 88 Total operating costs and expenses 8,042 7,408 427 522 275 (2,058 ) 14,616 Gain on sale of assets 19 — — — — — 19 Operating income/(loss) 1,265 (15 ) (83 ) 306 (256 ) 54 1,271 Equity in earnings/(losses)of unconsolidated affiliates 23 — (4 ) 17 — 2 38 Other income, net 39 — 1 6 75 (99 ) 22 Gain on sale of equity method investment 18 — — — — — 18 Loss on debt extinguishment — — (1 ) (1 ) (93 ) — (95 ) Interest expense (94 ) (2 ) (97 ) (216 ) (806 ) 96 (1,119 ) Income/(loss) before income taxes 1,251 (17 ) (184 ) 112 (1,080 ) 53 135 Income tax expense/(benefit) 3 1 — 4 (5 ) — 3 Net income/(loss) $ 1,248 (18 ) (184 ) 108 (1,075 ) 53 132 Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (1 ) — 2 16 5 (24 ) (2 ) Net income/(loss) attributable to NRG Energy, Inc. $ 1,249 $ (18 ) $ (186 ) $ 92 $ (1,080 ) $ 77 $ 134 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 1,873 $ 7 $ 25 $ 12 $ 85 $ — $ 2,002 As of December 31, 2016, the Company's businesses were segregated as follows: Generation (previously named Generation/Business), which includes generation, international and business solutions; Retail Mass (previously NRG Home Retail); Renewables (previously named NRG Renew), which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. The Company's corporate segment included BETM, residential solar (previously part of NRG Home) and electric vehicle services. During 2016, the Company began reporting the results of its residential solar business in its corporate segment and its international business in its Generation segment. The financial information for years ended December 31, 2016 , 2015 , and 2014 have been recast to reflect these changes. NRG Yield includes certain of the Company's contracted generation assets. On September 1, 2016 NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. This acquisition was accounted for as transfers of entities under common control and accordingly, all historical periods have been recast to reflect this change. For the Year Ended December 31, 2016 Generation (a) Retail Mass (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 6,927 $ 4,966 $ 417 $ 1,021 $ 137 $ (1,117 ) $ 12,351 Operating expenses 6,020 3,987 215 322 235 (1,123 ) 9,656 Depreciation and amortization 712 104 190 297 64 — 1,367 Impairment losses 646 — 56 183 33 — 918 Acquisition-related transaction and integration costs — — — 1 7 — 8 Development costs 26 — 40 — 24 — 90 Total operating cost and expenses 7,404 4,091 501 803 363 (1,123 ) 12,039 Gain/(loss) on sale of assets 293 — — — (78 ) — 215 Operating (loss)/income (184 ) 875 (84 ) 218 (304 ) 6 527 Equity in (losses)/earnings of unconsolidated affiliates (5 ) — (30 ) 37 7 18 27 Impairment losses on investments (142 ) — (105 ) — (21 ) — (268 ) Other income, net 37 — 1 3 62 (61 ) 42 Loss on debt extinguishment — — — — (142 ) — (142 ) Interest expense (80 ) — (108 ) (274 ) (658 ) 59 (1,061 ) (Loss)/income before income taxes (374 ) 875 (326 ) (16 ) (1,056 ) 22 (875 ) Income tax (benefit)/expense — — (20 ) (1 ) 37 — 16 Net (loss)/income $ (374 ) $ 875 $ (306 ) $ (15 ) $ (1,093 ) $ 22 $ (891 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — — (13 ) (54 ) 16 (66 ) (117 ) Net (loss)/income attributable to NRG Energy, Inc. $ (374 ) $ 875 $ (293 ) $ 39 $ (1,109 ) $ 88 $ (774 ) Balance sheet Equity investments in affiliates $ 204 $ — $ 372 $ 710 $ 91 $ (257 ) $ 1,120 Capital expenditures (b) 779 59 330 23 51 — 1,242 Goodwill 199 340 12 — 111 — 662 Total assets $ 13,234 $ 1,589 $ 5,280 $ 8,383 $ 15,734 $ (13,865 ) $ 30,355 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 893 $ 2 $ 23 $ 8 $ 191 $ — $ 1,117 (b) Includes accruals. For the Year Ended December 31, 2015 Generation (a) Retail Mass (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 9,097 $ 5,389 $ 392 $ 953 $ 14 $ (1,171 ) $ 14,674 Operating expenses 7,744 4,561 184 333 310 (1,149 ) 11,983 Depreciation and amortization 907 123 180 297 59 — 1,566 Impairment losses 4,827 36 13 — 132 22 5,030 Acquisition-related transaction and integration costs — 1 — 3 6 — 10 Development costs 31 — 52 — 63 — 146 Total operating cost and expenses 13,509 4,721 429 633 570 (1,127 ) 18,735 Gain on postretirement benefits curtailment 21 — — — — — 21 Operating (loss)/income (4,391 ) 668 (37 ) 320 (556 ) (44 ) (4,040 ) Equity in earnings/(losses) of unconsolidated affiliates 10 — 9 26 (3 ) (6 ) 36 Impairment losses on investments (14 ) — — — (42 ) — (56 ) Other income, net 48 — 3 3 77 (98 ) 33 (Loss)/gain on debt extinguishment — — — (9 ) 84 — 75 Loss on sale of equity method investment — — — — (14 ) — (14 ) Interest expense (98 ) — (83 ) (263 ) (779 ) 95 (1,128 ) (Loss)/income before income taxes (4,445 ) 668 (108 ) 77 (1,233 ) (53 ) (5,094 ) Income tax expense/(benefit) 1 — (18 ) 12 1,347 — 1,342 Net (loss)/income (4,446 ) 668 (90 ) 65 (2,580 ) (53 ) (6,436 ) Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests — — 6 19 (37 ) (42 ) (54 ) Net (loss)/income attributable to NRG Energy, Inc. $ (4,446 ) $ 668 $ (96 ) $ 46 $ (2,543 ) $ (11 ) $ (6,382 ) Balance sheet Equity investments in affiliates $ 334 $ — $ 134 $ 697 $ 127 $ (247 ) $ 1,045 Capital expenditures (b) 798 30 163 30 246 — 1,267 Goodwill 536 340 12 — 111 — 999 Total assets $ 17,324 $ 1,876 $ 5,142 $ 8,689 $ 19,926 $ (20,075 ) $ 32,882 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 898 $ 6 $ 25 $ 29 $ 213 $ — $ 1,171 (b) Includes accruals. For the Year Ended December 31, 2014 Generation (a) Retail Mass (a) Renewables (a) NRG Yield (a) Corporate (a) Eliminations Total (In millions) Operating revenues (a) $ 11,113 $ 5,503 $ 344 $ 828 $ 82 $ (2,002 ) $ 15,868 Operating expenses 8,993 5,236 191 285 171 (2,052 ) 12,824 Depreciation and amortization 966 122 164 233 38 — 1,523 Impairment losses 87 — 32 — (22 ) — 97 Acquisition-related transaction and integration costs 1 3 — 4 76 — 84 Development costs 13 — 40 — 35 — 88 Total operating costs and expenses 10,060 5,361 427 522 298 (2,052 ) 14,616 Gain on sale of assets 19 — — — — — 19 Operating income/(loss) 1,072 142 (83 ) 306 (216 ) 50 1,271 Equity in earnings/(losses)of unconsolidated affiliates 23 — (4 ) 17 — 2 38 Other income, net 39 — 1 6 75 (99 ) 22 Gain on sale of equity method investment 18 — — — — — 18 Loss on debt extinguishment — — (1 ) (1 ) (93 ) — (95 ) Interest expense (95 ) (1 ) (97 ) (216 ) (806 ) 96 (1,119 ) Income/(loss) before income taxes 1,057 141 (184 ) 112 (1,040 ) 49 135 Income tax expense/(benefit) 4 — — 4 (5 ) — 3 Net income/(loss) 1,053 141 (184 ) 108 (1,035 ) 49 132 Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (1 ) — 2 16 5 (24 ) (2 ) Net income/(loss) attributable to NRG Energy, Inc. $ 1,054 $ 141 $ (186 ) $ 92 $ (1,040 ) $ 73 $ 134 (a) Inter-segment sales and net derivative gains and losses included in operating revenues $ 1,873 $ 7 $ 25 $ 12 $ 85 $ — $ 2,002

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Reconciliation of NRG's basic and diluted earnings per share	The reconciliation of NRG's basic earnings/(loss) per share to diluted earnings/(loss) per share is shown in the following table: Year Ended December 31, 2016 2015 2014 (In millions, except per share amounts) Basic (loss)/earnings per share attributable to NRG common stockholders Net (loss)/income attributable to NRG Energy, Inc. $ (774 ) $ (6,382 ) $ 134 Dividends for preferred shares 5 20 9 Dividends for refinancing of preferred shares — — 47 Gain on redemption of 2.822% redeemable perpetual preferred shares (78 ) — — (Loss)/Income Available to Common Stockholders $ (701 ) $ (6,402 ) $ 78 Weighted average number of common shares outstanding 316 329 334 (Loss)/Earnings per weighted average common share — basic $ (2.22 ) $ (19.46 ) $ 0.23 Diluted (loss)/earnings per share attributable to NRG common stockholders Weighted average number of common shares outstanding 316 329 334 Incremental shares attributable to the issuance of equity compensation (treasury stock method) — — 5 Total dilutive shares 316 329 339 (Loss)/Earnings per weighted average common share — diluted $ (2.22 ) $ (19.46 ) $ 0.23
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 earnings/(loss) per share: Year Ended December 31, 2016 2015 2014 (In millions of shares) Equity compensation 5 6 1 Embedded derivative of 2.822% redeemable perpetual preferred stock — 16 16 Total 5 22 17

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (In millions, except percentages) Current State $ 17 $ 6 $ 8 Total — current 17 6 8 Deferred U.S. Federal 3 1,020 (50 ) State (6 ) 315 41 Foreign 2 1 4 Total — deferred (1 ) 1,336 (5 ) Total income tax expense $ 16 $ 1,342 $ 3 Effective tax rate (1.8 )% (26.3 )% 2.2 %
Domestic and foreign components of income/(loss) before income tax (benefit)/expense	The following represents the domestic and foreign components of income/(loss) before income tax expense/(benefit): Year Ended December 31, 2016 2015 2014 (In millions) U.S. $ (886 ) $ (5,105 ) $ 126 Foreign 11 11 9 Total $ (875 ) $ (5,094 ) $ 135
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, 2016 2015 2014 (In millions, except percentages) (Loss)/income before income taxes $ (875 ) $ (5,094 ) $ 135 Tax at 35% (306 ) (1,783 ) 47 State taxes 11 (218 ) 9 Foreign operations 10 1 1 Federal and state tax credits, excluding PTCs — (5 ) (1 ) Valuation allowance 306 3,039 6 Impact of non-taxable equity earnings 22 (10 ) (11 ) Book goodwill impairment — 340 — Net interest accrued on uncertain tax positions 1 (3 ) (2 ) Production tax credit (26 ) (33 ) (48 ) Recognition of uncertain tax benefits 2 (15 ) (30 ) Tax expense attributable to consolidated partnerships (1 ) 12 4 Impact of change in effective state tax rate 1 19 22 Other (4 ) (2 ) 6 Income tax expense $ 16 $ 1,342 $ 3 Effective income tax rate (1.8 )% (26.3 )% 2.2 %
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, 2016 2015 (In millions) Deferred tax liabilities: Emissions allowances $ 30 $ 31 Derivatives, net — 22 Cumulative translation adjustments 11 2 Investment in projects 374 838 Total deferred tax liabilities 415 893 Deferred tax assets: Deferred compensation, accrued vacation and other reserves 318 255 Discount/premium on notes 45 68 Difference between book and tax basis of property 1,511 1,210 Goodwill 83 39 Differences between book and tax basis of contracts 301 516 Pension and other postretirement benefits 183 218 Equity compensation 11 50 Bad debt reserve 12 6 U.S. capital loss carryforwards 1 1 U.S. Federal net operating loss carryforwards 1,171 1,373 Foreign net operating loss carryforwards 63 59 State net operating loss carryforwards 223 230 Foreign capital loss carryforwards 1 1 Deferred financing costs 4 6 Federal and state tax credit carryforwards 446 439 Federal benefit on state uncertain tax positions 12 17 Intangibles amortization (excluding goodwill) 211 90 Derivatives, net 101 — Inventory obsolescence 31 27 Other 8 11 Total deferred tax assets 4,736 4,616 Valuation allowance (4,116 ) (3,575 ) Total deferred tax assets, net of valuation allowance 620 1,041 Net deferred tax asset $ 205 $ 148
Summary of NRG's net deferred tax position	The following table summarizes NRG's net deferred tax position: As of December 31, 2016 2015 (In millions) Net deferred tax asset — noncurrent $ 225 $ 167 Net deferred tax liability — noncurrent (20 ) (19 ) Net deferred tax asset $ 205 $ 148
Reconciliation of total amounts of uncertain tax benefits	The following table reconciles the total amounts of uncertain tax benefits: As of December 31, 2016 2015 (In millions) Balance as of January 1 $ 32 $ 71 Increase due to current year positions 8 4 Decrease due to prior year positions — (25 ) Decrease due to settlements and payments (6 ) (18 ) Uncertain tax benefits as of December 31 $ 34 $ 32

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Share-based Compensation [Abstract]
Schedule of Share-based Payment Awards, Market Unit Valuation Assumptions [Table Text Block]	Significant assumptions used in the fair value model with respect to the Company's MSUs are summarized below: 2016 2015 Expected volatility 34.33 % 24.08%-25.20% Expected term (in years) 3 1-3 Risk free rate 1.31 % 0.25%-1.07%
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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 Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (In years) (In millions) Outstanding at December 31, 2015 2,071,913 $ 32.27 3 $ — Forfeited (548,994 ) 52.34 Outstanding at December 31, 2016 1,522,919 25.03 3 — Exercisable at December 31, 2016 1,522,919 25.03 3 —
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 total intrinsic value of options exercised and the cash received from the exercises of options: Year Ended December 31, 2016 2015 2014 (In millions) Total intrinsic value of options exercised $ — $ 2 $ 7 Cash received from options exercised — 9 21
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 Non-vested at December 31, 2015 2,261,996 $ 27.59 Granted 1,226,957 11.54 Forfeited (592,163 ) 22.91 Vested (916,649 ) 26.07 Non-vested at December 31, 2016 1,980,141 19.29
Summary of significant assumptions used in the fair value model with respect to the Company's MSUs	The following table summarizes the Company's outstanding DSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit Outstanding at December 31, 2015 427,578 $ 21.88 Granted 102,147 16.85 Converted to Common Stock (76,051 ) 18.37 Outstanding at December 31, 2016 453,674 21.54
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	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, 2016 for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $5 million , $21 million , and $16 million for the years ended December 31, 2016 , 2015 , and 2014 , 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 Total Cost Weighted Average Recognition Period Remaining (In years) Year Ended December 31 As of December 31 Award 2016 2015 2014 2016 2016 (In millions, except weighted average data) NQSOs (a) $ — $ — $ 1 $ — — RSUs 14 23 20 12 1.46 DSUs 2 2 2 — — MSUs 3 16 19 7 1.54 PRSUs (b) 5 — — 8 1.30 Total $ 24 $ 41 $ 42 $ 27 Tax detriment recognized $ (4 ) $ (12 ) $ (8 ) (a) All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2016 and 2015. (b) Phantom Restricted Stock Units, PRSUs, are liability-classified time-based awards that typically vest ratably over a three -year period. The amount to be paid upon vesting is based on NRG's closing stock price for the period.
Market Stock Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of Company's outstanding DSU 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 Non-vested at December 31, 2015 1,980,157 $ 29.54 Granted 806,409 14.73 Forfeited (1,499,963 ) 27.76 Vested (4,015 ) 33.81 Non-vested at December 31, 2016 1,282,588 21.47

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
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 third party affiliates that are included in the Company's operating revenues, operating costs and other income and expense: Year Ended December 31, 2016 2015 2014 (In millions) Revenues from Related Parties Included in Operating Revenues Gladstone $ 2 $ 4 $ 6 GenConn 5 4 6 Total $ 7 $ 8 $ 12

Commitments and Contingencies58

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Other Commitments [Line Items]
Commitments under coal, gas and transportation contractual agreements	As of December 31, 2016 , the Company's commitments under such outstanding agreements are as follows: Period (In millions) 2017 $ 638 2018 251 2019 174 2020 140 2021 109 Thereafter 415 Total $ 1,727
Minimum purchase commitment obligations under purchased power agreements	Minimum purchase commitment obligations are as follows as of December 31, 2016 : Period (In millions) 2017 $ 25 2018 17 2019 13 2020 11 2021 21 Thereafter — Total (a) $ 87 (a) As of December 31, 2016 , the maximum remaining term under any individual purchased power contract is five years.
EME [Member]
Other Commitments [Line Items]
Future minimum lease commitments under operating leases	Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31, 2016 , are as follows: Period (In millions) 2017 $ 1 2018 1 2019 1 2020 1 2021 3 Thereafter 234 Total $ 241
REMA [Member]
Other Commitments [Line Items]
Future minimum lease commitments under operating leases	Future minimum lease commitments under the REMA operating leases for the years ending after December 31, 2016 are as follows: Period (In millions) 2017 $ 63 2018 55 2019 65 2020 56 2021 47 Thereafter 231 Total $ 517
GenOn Mid-Atlantic
Other Commitments [Line Items]
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, 2016 are as follows: Period (In millions) 2017 $ 144 2018 105 2019 139 2020 105 2021 42 Thereafter 400 Total $ 935
Other Leased Property [Member]
Other Commitments [Line Items]
Future minimum lease commitments under operating leases	Future minimum lease commitments under operating leases for the years ending after December 31, 2016 are as follows: Period (In millions) 2017 $ 84 2018 76 2019 67 2020 61 2021 52 Thereafter 443 Total (a) $ 783 (a) Amounts in the table exclude future sublease income of $14 million associated with long-term leases for office locations.

Cash Flow Information (Tables)

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (In millions) Interest paid, net of amount capitalized $ 1,106 $ 1,172 $ 1,067 Income taxes (refunded)/paid (a) 27 16 (6 ) Consent fee paid, preferred stock — — 5 Non-cash investing and financing activities: (Decrease)/additions to fixed assets for accrued capital expenditures (33 ) (24 ) 87 Decrease to fixed assets for accrued grants and related tax impact — — (711 ) Issuance of shares for EME acquisition — — (401 ) (a) In 2016 , the net income taxes paid reflect $29 million in income taxes paid and $2 million in income tax refunds. In 2015 , the net income taxes refunded are net of $17 million income taxes paid and $1 million income tax refunds. In 2014 , the net income taxes refunded are net of $15 million income taxes paid and $21 million income tax refunds.

Guarantees Guarantees (Tables)

Guarantees Guarantees (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 Guarantees Under 1 Year 1-3 Years 3-5 Years Over 5 Years Total 2015 Total (In millions) Letters of credit and surety bonds $ 2,122 $ 80 $ — $ 15 $ 2,217 $ 1,899 Asset sales guarantee obligations — 420 — 257 677 257 Other guarantees — — 5 731 736 722 Total guarantees $ 2,122 $ 500 $ 5 $ 1,003 $ 3,630 $ 2,878

Jointly Owned Plants (Tables)

Jointly Owned Plants (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress (In millions unless otherwise stated) South Texas Project Units 1 and 2, Bay City, TX 44.00 % $ 3,275 $ (1,734 ) $ 39 Big Cajun II Unit 3, New Roads, LA 58.00 % 204 123 — Cedar Bayou Unit 4, Baytown, TX 50.00 % 216 (67 ) 5 Keystone, Shelocta, PA 3.70 % 97 (48 ) — Conemaugh, New Florence, PA 3.72 % 103 (51 ) 1

Unaudited Quarterly Financial62

Unaudited Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Summary of Unaudited Quarterly Financial Data	Summarized unaudited quarterly financial data is as follows: Quarter Ended 2016 December 31 September 30 June 30 March 31 (In millions, except per share data) Operating revenues $ 2,532 $ 3,952 $ 2,638 $ 3,229 Operating (loss)/income (791 ) 755 87 476 Net (loss)/income (1,055 ) 393 (276 ) 47 Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests (68 ) (9 ) (5 ) (35 ) Net (loss)/income attributable to NRG Energy, Inc. (987 ) 402 (271 ) 82 (Loss)/income available to Common Stockholders $ (987 ) $ 402 $ (193 ) $ 77 Weighted average number of common shares outstanding — basic 316 316 315 315 Net (loss)/income per weighted average common share — basic $ (3.13 ) $ 1.27 $ (0.61 ) $ 0.24 Weighted average number of common shares outstanding — diluted 316 317 315 315 Net (loss)/income per weighted average common share — diluted $ (3.13 ) $ 1.27 $ (0.61 ) $ 0.24 Quarter Ended 2015 December 31 September 30 June 30 March 31 (In millions, except per share data) Operating revenues $ 3,011 $ 4,434 $ 3,400 $ 3,829 Operating (loss)/income (4,727 ) 379 232 76 Net (loss)/income (6,358 ) 67 (9 ) (136 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (44 ) 1 5 (16 ) Net (loss)/income attributable to NRG Energy, Inc. (6,314 ) 66 (14 ) (120 ) (Loss)/income available to Common Stockholders $ (6,319 ) $ 61 $ (19 ) $ (125 ) Weighted average number of common shares outstanding — basic 315 331 333 336 Net (loss)/income per weighted average common share — basic $ (20.08 ) $ 0.18 $ (0.06 ) $ 0.37 Weighted average number of common shares outstanding — diluted 315 332 333 336 Net (loss)/income per weighted average common share — diluted $ (20.08 ) $ 0.18 $ (0.06 ) $ (0.37 )

Condensed Consolidating Finan63

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 : Ace Energy, Inc. NEO Freehold-Gen LLC NRG Operating Services, Inc. Allied Warranty LLC NEO Power Services Inc. NRG Oswego Harbor Power Operations Inc. Arthur Kill Power LLC New Genco GP, LLC NRG PacGen Inc. Astoria Gas Turbine Power LLC Norwalk Power LLC NRG Portable Power LLC Bayou Cove Peaking Power LLC NRG Affiliate Services Inc. NRG Power Marketing LLC BidURenergy, Inc. NRG Artesian Energy LLC NRG Reliability Solutions LLC Cabrillo Power I LLC NRG Arthur Kill Operations Inc. NRG Renter's Protection LLC Cabrillo Power II LLC NRG Astoria Gas Turbine Operations Inc. NRG Retail LLC Carbon Management Solutions LLC NRG Bayou Cove LLC NRG Retail Northeast LLC Cirro Group, Inc. NRG Business Solutions LLC NRG Rockford Acquisition LLC Cirro Energy Services, Inc. NRG Cabrillo Power Operations Inc. NRG Saguaro Operations Inc. Clean Edge Energy LLC NRG California Peaker Operations LLC NRG Security LLC Conemaugh Power LLC NRG Cedar Bayou Development Company, LLC NRG Services Corporation Connecticut Jet Power LLC NRG Connected Home LLC NRG SimplySmart Solutions LLC Cottonwood Development LLC NRG Connecticut Affiliate Services Inc. NRG South Central Affiliate Services Inc. Cottonwood Energy Company LP NRG Construction LLC NRG South Central Generating LLC Cottonwood Generating Partners I LLC NRG Curtailment Solutions LLC NRG South Central Operations Inc. Cottonwood Generating Partners II LLC NRG Development Company Inc. NRG South Texas LP Cottonwood Generating Partners III LLC NRG Devon Operations Inc. NRG Texas C&I Supply LLC Cottonwood Technology Partners LP NRG Dispatch Services LLC NRG Texas Gregory LLC Devon Power LLC NRG Distributed Generation PR LLC NRG Texas Holding Inc. Dunkirk Power LLC NRG Dunkirk Operations Inc. NRG Texas LLC Eastern Sierra Energy Company LLC NRG El Segundo Operations Inc. NRG Texas Power LLC El Segundo Power, LLC NRG Energy Efficiency-L LLC NRG Warranty Services LLC El Segundo Power II LLC NRG Energy Efficiency-P LLC NRG West Coast LLC Energy Alternatives Wholesale, LLC NRG Energy Labor Services LLC NRG Western Affiliate Services Inc. Energy Choice Solutions, LLC NRG ECOKAP Holdings, LLC O'Brien Cogeneration, Inc. II NRG Curtailment Solutions, Inc. NRG Energy Services Group LLC ONSITE Energy, Inc. Energy Plus Holdings LLC NRG Energy Services International Inc. Oswego Harbor Power LLC Energy Plus Natural Gas LLC NRG Energy Services LLC RE Retail Receivables, LLC Energy Protection Insurance Company NRG Generation Holdings, Inc. Reliant Energy Northeast LLC Everything Energy LLC NRG Home & Business Solutions LLC Reliant Energy Power Supply, LLC Forward Home Security, LLC NRG Home Solutions LLC Reliant Energy Retail Holdings, LLC GCP Funding Company, LLC NRG Home Solutions Product LLC Reliant Energy Retail Services, LLC Green Mountain Energy Company NRG Homer City Services LLC RERH Holdings LLC Gregory Partners, LLC NRG Huntley Operations Inc. Saguaro Power LLC Gregory Power Partners LLC NRG HQ DG LLC Somerset Operations Inc. Huntley Power LLC NRG Identity Protect LLC Somerset Power LLC Independence Energy Alliance LLC NRG Ilion Limited Partnership Texas Genco Financing Corp. Independence Energy Group LLC NRG Ilion LP LLC Texas Genco GP, LLC Independence Energy Natural Gas LLC NRG International LLC Texas Genco Holdings, Inc. Indian River Operations Inc. NRG Maintenance Services LLC Texas Genco LP, LLC Indian River Power LLC NRG Mextrans Inc. Texas Genco Operating Services, LLC Keystone Power LLC NRG MidAtlantic Affiliate Services Inc. Texas Genco Services, LP Langford Wind Power LLC NRG Middletown Operations Inc. US Retailers LLC NRG Home Services LLC NRG Montville Operations Inc. Vienna Operations Inc. Louisiana Generating LLC NRG New Roads Holdings LLC Vienna Power LLC Meriden Gas Turbines LLC NRG North Central Operations Inc. WCP (Generation) Holdings LLC Middletown Power LLC NRG Northeast Affiliate Services Inc. West Coast Power LLC Montville Power LLC NRG Norwalk Harbor Operations Inc. NEO Corporation NRG GreenCo, LLC NRG Business Services LLC NRG GreenCo Holdings, LLC
Condensed Consolidating Statement of Operations	NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2016 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 7,509 $ 5,082 $ — $ (240 ) $ 12,351 Operating Costs and Expenses Cost of operations 5,402 3,355 42 (244 ) 8,555 Depreciation and amortization 565 776 26 — 1,367 Impairment losses 378 540 — — 918 Selling, general and administrative 415 397 289 — 1,101 Acquisition-related transaction and integration costs — 1 7 — 8 Development costs — 60 30 — 90 Total operating costs and expenses 6,760 5,129 394 (244 ) 12,039 Gain/(loss) on sale of assets — 294 (79 ) — 215 Operating Income/(Loss) 749 247 (473 ) 4 527 Other Income/(Expense) Equity in (losses)/earnings of consolidated subsidiaries (148 ) (58 ) 313 (107 ) — Equity in earnings/(losses) of unconsolidated affiliates 5 37 (5 ) (10 ) 27 Impairment losses on investments — (268 ) — — (268 ) Other income/(loss), net 4 46 (6 ) (2 ) 42 Net loss on debt extinguishment — (4 ) (138 ) — (142 ) Interest expense (15 ) (574 ) (472 ) — (1,061 ) Total other expense (154 ) (821 ) (308 ) (119 ) (1,402 ) Income/(Loss) Before Income Taxes 595 (574 ) (781 ) (115 ) (875 ) Income tax expense/(benefit) (1 ) 18 (63 ) 62 16 Net Income/(Loss) 596 (592 ) (718 ) (177 ) (891 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (103 ) 56 (70 ) (117 ) Net Income/(Loss) Attributable to NRG Energy, Inc. $ 596 $ (489 ) $ (774 ) $ (107 ) $ (774 ) (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, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 10,024 $ 4,768 $ — $ (118 ) $ 14,674 Operating Costs and Expenses Cost of operations 7,712 3,176 14 (118 ) 10,784 Depreciation and amortization 787 759 20 — 1,566 Impairment losses 4,655 375 — — 5,030 Selling, general and administrative 467 382 350 — 1,199 Acquisition-related transactions and integration costs 1 (5 ) 14 — 10 Development costs — 53 93 — 146 Total operating costs and expenses 13,622 4,740 491 (118 ) 18,735 Gain on postretirement benefits curtailment — 21 — — 21 Operating (Loss)/Income (3,598 ) 49 (491 ) — (4,040 ) Other Income/(Expense) Equity in losses of consolidated subsidiaries (86 ) (29 ) (2,799 ) 2,914 — Equity in earnings of unconsolidated affiliates 8 37 — (9 ) 36 Impairment losses on investments — (25 ) (31 ) — (56 ) Other income, net 4 29 — — 33 Loss on sale of equity method investment — — (14 ) — (14 ) Net gain on debt extinguishment — 56 19 — 75 Interest expense (18 ) (564 ) (546 ) — (1,128 ) Total other expense (92 ) (496 ) (3,371 ) 2,905 (1,054 ) Loss Before Income Taxes (3,690 ) (447 ) (3,862 ) 2,905 (5,094 ) Income tax (benefit)/expense (1,104 ) (96 ) 2,489 53 1,342 Net Loss (2,586 ) (351 ) (6,351 ) 2,852 (6,436 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (23 ) 31 (62 ) (54 ) Net Loss Attributable to NRG Energy, Inc. $ (2,586 ) $ (328 ) $ (6,382 ) $ 2,914 $ (6,382 ) (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, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 9,974 $ 6,287 $ — $ (393 ) $ 15,868 Operating Costs and Expenses Cost of operations 7,909 4,220 4 (325 ) 11,808 Depreciation and amortization 801 706 16 — 1,523 Impairment losses — 119 — (22 ) 97 Selling, general and administrative 333 379 304 — 1,016 Acquisition-related transaction and integration costs 3 15 66 — 84 Development costs — 32 56 — 88 Total operating costs and expenses 9,046 5,471 446 (347 ) 14,616 Gain on sale of assets — 19 — — 19 Operating Income/(Loss) 928 835 (446 ) (46 ) 1,271 Other Income/(Expense) Equity in earnings of consolidated subsidiaries 317 219 775 (1,311 ) — Equity in earnings of unconsolidated affiliates 13 33 — (8 ) 38 Other income, net 7 14 3 (2 ) 22 Gain on sale of equity method investment — 18 — — 18 Loss on debt extinguishment — (9 ) (86 ) — (95 ) Interest expense (19 ) (525 ) (575 ) — (1,119 ) Total other income/(expense) 318 (250 ) 117 (1,321 ) (1,136 ) Income/(Loss) Before Income Taxes 1,246 585 (329 ) (1,367 ) 135 Income tax expense/(benefit) 322 159 (478 ) — 3 Net Income 924 426 149 (1,367 ) 132 Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests — 57 15 (74 ) (2 ) Net Income Attributable to NRG Energy, Inc $ 924 $ 369 $ 134 $ (1,293 ) $ 134 (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/(LOSS) For the Year Ended December 31, 2016 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Income/(Loss) $ 596 $ (592 ) $ (718 ) $ (177 ) $ (891 ) Other Comprehensive Income/(Loss), net of tax Unrealized gain on derivatives, net — 32 89 (86 ) 35 Foreign currency translation adjustments, net (1 ) (1 ) (1 ) 2 (1 ) Available-for-sale securities, net — — 1 — 1 Defined benefit plan, net 36 (23 ) (51 ) 41 3 Other comprehensive income 35 8 38 (43 ) 38 Comprehensive Income/(Loss) 631 (584 ) (680 ) (220 ) (853 ) Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (103 ) 56 (70 ) (117 ) Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. 631 (481 ) (736 ) (150 ) (736 ) Dividends for preferred shares — — 5 — 5 Gain on redemption of preferred shares — — (78 ) — (78 ) Comprehensive Income/(Loss) Available for Common Stockholders $ 631 $ (481 ) $ (663 ) $ (150 ) $ (663 ) (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, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Loss $ (2,586 ) $ (351 ) $ (6,351 ) $ 2,852 $ (6,436 ) Other Comprehensive (Loss)/Income, net of tax Unrealized (loss)/gain on derivatives, net (9 ) (13 ) 48 (41 ) (15 ) Foreign currency translation adjustments, net — (7 ) (4 ) — (11 ) Available-for-sale securities, net — (1 ) 18 — 17 Defined benefit plan, net (22 ) (15 ) (42 ) 89 10 Other comprehensive (loss)/income (31 ) (36 ) 20 48 1 Comprehensive Loss (2,617 ) (387 ) (6,331 ) 2,900 (6,435 ) Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (42 ) 31 (62 ) (73 ) Comprehensive Loss Attributable to NRG Energy, Inc. (2,617 ) (345 ) (6,362 ) 2,962 (6,362 ) Dividends for preferred shares — — 20 — 20 Comprehensive Loss Available for Common Stockholders $ (2,617 ) $ (345 ) $ (6,382 ) $ 2,962 $ (6,382 ) (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, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Income $ 924 $ 426 $ 149 $ (1,367 ) $ 132 Other Comprehensive (Loss)/Income, net of tax Unrealized loss on derivatives, net (49 ) (89 ) (215 ) 308 (45 ) Foreign currency translation adjustments, net — (12 ) 4 — (8 ) Available-for-sale securities, net — 1 (8 ) — (7 ) Defined benefit plan, net 5 (104 ) 20 (50 ) (129 ) Other comprehensive loss (44 ) (204 ) (199 ) 258 (189 ) Comprehensive Income/(Loss) 880 222 (50 ) (1,109 ) (57 ) Less: Comprehensive income attributable to noncontrolling interest — 67 15 (74 ) 8 Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. 880 155 (65 ) (1,035 ) (65 ) Dividends for preferred shares — — 56 — 56 Comprehensive Income/(Loss) Available for Common Stockholders $ 880 $ 155 $ (121 ) $ (1,035 ) $ (121 ) (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, 2016 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) ASSETS Current Assets Cash and cash equivalents $ — $ 1,650 $ 323 $ — $ 1,973 Funds deposited by counterparties 2 — — — 2 Restricted cash 11 435 — — 446 Accounts receivable - trade, net 734 429 3 — 1,166 Accounts receivable - Affiliate 309 (241 ) 200 (262 ) 6 Inventory 482 629 — — 1,111 Derivative instruments 962 305 — (205 ) 1,062 Cash collateral posted in support of energy risk management activities 37 166 — — 203 Current assets held-for-sale — 9 — — 9 Prepayments and other current assets 76 279 62 — 417 Total current assets 2,613 3,661 588 (467 ) 6,395 Net Property, Plant and Equipment 4,216 13,472 251 (27 ) 17,912 Other Assets Investment in subsidiaries 837 1,973 10,128 (12,938 ) — Equity investments in affiliates (14 ) 1,129 5 — 1,120 Notes receivable, less current portion — 17 (76 ) 76 17 Goodwill 359 303 — — 662 Intangible assets, net 592 1,447 — (3 ) 2,036 Nuclear decommissioning trust fund 610 — — — 610 Deferred income taxes 3 868 (646 ) — 225 Derivative instruments 143 60 36 (50 ) 189 Non-current assets held for sale — 10 — — 10 Other non-current assets 67 784 328 — 1,179 Total other assets 2,597 6,591 9,775 (12,915 ) 6,048 Total Assets $ 9,426 $ 23,724 $ 10,614 $ (13,409 ) $ 30,355 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and capital leases $ — $ 1,202 $ (58 ) $ 76 $ 1,220 Accounts payable 499 362 34 — 895 Accounts payable - affiliate 655 1,834 (2,227 ) (262 ) — Derivative instruments 947 342 — (205 ) 1,084 Cash collateral received in support of energy risk management activities 2 — — — 2 Accrued interest expense 3 94 123 — 220 Other accrued expenses 110 140 293 — 543 Other current liabilities 204 166 48 — 418 Total current liabilities 2,420 4,140 (1,787 ) (391 ) 4,382 Other Liabilities Long-term debt and capital leases 244 10,302 7,460 — 18,006 Nuclear decommissioning reserve 287 — — — 287 Nuclear decommissioning trust liability 339 — — — 339 Postretirement and other benefit obligations 114 189 250 — 553 Deferred income taxes 186 (1,094 ) 928 — 20 Derivative instruments 157 187 — (50 ) 294 Out-of-market contracts 80 960 — — 1,040 Non-current liabilities held-for-sale — 12 — — 12 Other non-current liabilities 283 573 74 — 930 Total non-current liabilities 1,690 11,129 8,712 (50 ) 21,481 Total Liabilities 4,110 15,269 6,925 (441 ) 25,863 2.822% Preferred Stock — — — — — Redeemable noncontrolling interest in subsidiaries — 46 — — 46 Stockholders' Equity 5,316 8,409 3,689 (12,968 ) 4,446 Total Liabilities and Stockholders' Equity $ 9,426 $ 23,724 $ 10,614 $ (13,409 ) $ 30,355 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) ASSETS Current Assets Cash and cash equivalents $ — $ 825 $ 693 $ — $ 1,518 Funds deposited by counterparties 55 51 — — 106 Restricted cash 5 409 — — 414 Accounts receivable - trade, net 851 304 2 — 1,157 Inventory 570 682 — — 1,252 Derivative instruments 1,202 871 — (158 ) 1,915 Cash collateral posted in support of energy risk management activities 474 94 — — 568 Accounts receivable - affiliate 395 260 571 (1,222 ) 4 Current assets held-for-sale — 6 — — 6 Prepayments and other current assets 93 287 71 — 451 Total current assets 3,645 3,789 1,337 (1,380 ) 7,391 Net Property, Plant and Equipment 4,767 13,773 219 (27 ) 18,732 Other Assets Investment in subsidiaries 842 2,244 11,039 (14,125 ) — Equity investments in affiliates (14 ) 1,160 1 (102 ) 1,045 Notes receivable, less current portion — 46 7 — 53 Goodwill 697 302 — — 999 Intangible assets, net 763 1,551 2 (6 ) 2,310 Nuclear decommissioning trust fund 561 — — — 561 Derivative instruments 153 184 — (32 ) 305 Deferred income taxes (6 ) 815 (642 ) — 167 Non-current assets held for sale — 105 — — 105 Other non-current assets 80 749 385 — 1,214 Total other assets 3,076 7,156 10,792 (14,265 ) 6,759 Total Assets $ 11,488 $ 24,718 $ 12,348 $ (15,672 ) $ 32,882 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and capital leases $ 2 $ 460 $ 19 $ — $ 481 Accounts payable 553 277 39 — 869 Accounts payable - affiliate 151 2,000 (929 ) (1,222 ) — Derivative instruments 1,130 749 — (158 ) 1,721 Cash collateral received in support of energy risk management activities 55 51 — — 106 Accrued interest expense 5 91 147 (1 ) 242 Other accrued expenses 122 151 295 — 568 Current liabilities held-for-sale — 2 — — 2 Other current liabilities 192 187 7 — 386 Total current liabilities 2,210 3,968 (422 ) (1,381 ) 4,375 Other Liabilities Long-term debt and capital leases 302 10,496 8,185 — 18,983 Nuclear decommissioning reserve 326 — — — 326 Nuclear decommissioning trust liability 283 — — — 283 Postretirement and other benefit obligations 236 200 152 — 588 Deferred income taxes 179 (1,088 ) 928 — 19 Derivative instruments 301 224 — (32 ) 493 Out-of-market contracts 95 1,051 — — 1,146 Non-current liabilities held-for-sale — 4 — — 4 Other non-current liabilities 318 535 47 — 900 Total non-current liabilities 2,040 11,422 9,312 (32 ) 22,742 Total Liabilities 4,250 15,390 8,890 (1,413 ) 27,117 2.822% Preferred Stock — — 302 — 302 Redeemable noncontrolling interest in subsidiaries — 29 — — 29 Stockholders' Equity 7,238 9,299 3,156 (14,259 ) 5,434 Total Liabilities and Stockholders' Equity $ 11,488 $ 24,718 $ 12,348 $ (15,672 ) $ 32,882 (a) All significant intercompany transactions have been eliminated in consolidation.
Condensed Consolidating Statements of Cash Flows	NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2016 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net income/(loss) $ 596 $ (592 ) $ (718 ) $ (177 ) $ (891 ) Adjustments to reconcile net income/(loss) to net cash provided by operating activities: Distributions from unconsolidated affiliates — 89 — (8 ) 81 Equity in earnings of unconsolidated affiliates (5 ) (37 ) 5 10 (27 ) Depreciation and amortization 565 776 26 — 1,367 Provision for bad debts 41 7 — — 48 Amortization of nuclear fuel 49 — — — 49 Amortization of financing costs and debt discount/premiums — (18 ) 21 — 3 Adjustment to loss on debt extinguishment — 4 17 — 21 Amortization of intangibles and out-of-market contracts 39 52 — — 91 Amortization of unearned equity compensation — — 10 — 10 Gain on sale of assets and equity method investments, net — (294 ) 70 — (224 ) Impairment losses 378 808 — — 1,186 Changes in derivative instruments (77 ) 136 (36 ) — 23 Changes in deferred income taxes and liability for uncertain tax benefits (1 ) 18 (60 ) — (43 ) Changes in collateral deposits supporting energy risk management activities 437 (72 ) — — 365 Proceeds from sale of emission allowances 47 — — — 47 Changes in nuclear decommissioning trust liability 41 — — — 41 Cash (used)/provided by changes in other working capital (1,806 ) 364 1,192 175 (75 ) Net Cash Provided by Operating Activities 304 1,241 527 — 2,072 Cash Flows from Investing Activities Dividends from NRG Yield, Inc. — — 81 (81 ) — Acquisition of September 2016 Drop Down Assets, net of cash acquired — (77 ) — 77 — Intercompany dividends — — 12 (12 ) — Acquisition of businesses, net of cash acquired — (209 ) — — (209 ) Capital expenditures (180 ) (1,016 ) (48 ) — (1,244 ) Increase in restricted cash, net (4 ) (25 ) — — (29 ) Increase in restricted cash - U.S. DOE projects — (3 ) — — (3 ) Decrease in notes receivable — 17 — — 17 Proceeds from renewable energy grants — 36 — — 36 Purchases of emission allowances, net of proceeds (1 ) — — — (1 ) Investments in nuclear decommissioning trust securities (551 ) — — — (551 ) Proceeds from sales of nuclear decommissioning trust fund securities 510 — — — 510 Proceeds from sale of assets, net — 619 17 — 636 Investments in unconsolidated affiliates 3 (37 ) — — (34 ) Other 27 13 8 — 48 Net Cash (Used)/Provided by Investing Activities (196 ) (682 ) 70 (16 ) (824 ) Cash Flows from Financing Activities Dividends from NRG Yield, Inc. — (81 ) — 81 — Payments (for)/from intercompany loans (52 ) (49 ) 101 — — Acquisition of September 2016 Drop Down Assets, net of cash acquired — — 77 (77 ) — Intercompany dividends (52 ) 40 — 12 — Payment of dividends to preferred and common stockholders — — (76 ) — (76 ) Net receipts from settlement of acquired derivatives that include financing elements — 151 — — 151 Payments for preferred shares — — (226 ) — (226 ) Distributions from, net of contributions to noncontrolling interests in subsidiaries — (156 ) — — (156 ) Proceeds from issuance of common stock — — 1 — 1 Proceeds from issuance of long-term debt — 1,387 4,140 — 5,527 Payments for short and long-term debt (1 ) (988 ) (4,924 ) — (5,913 ) Payment of debt issuance costs and hedging costs — (29 ) (60 ) — (89 ) Other (3 ) (10 ) — — (13 ) Net Cash (Used)/Provided by Financing Activities (108 ) 265 (967 ) 16 (794 ) Effect of exchange rate changes on cash and cash equivalents — 1 — — 1 Net Increase/(Decrease) in Cash and Cash Equivalents — 825 (370 ) — 455 Cash and Cash Equivalents at Beginning of Period — 825 693 — 1,518 Cash and Cash Equivalents at End of Period $ — $ 1,650 $ 323 $ — $ 1,973 (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, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net loss $ (2,586 ) $ (351 ) $ (6,351 ) $ 2,852 $ (6,436 ) Adjustments to reconcile net loss to net cash provided by operating activities: Distributions from unconsolidated affiliates 3 91 — (21 ) 73 Equity in earnings of unconsolidated affiliates (8 ) (37 ) — 9 (36 ) Depreciation and amortization 787 759 20 — 1,566 Provision for bad debts 58 3 3 — 64 Amortization of nuclear fuel 45 — — — 45 Amortization of financing costs and debt discount/premiums — (37 ) 26 — (11 ) Adjustment to gain on debt extinguishment — (56 ) (19 ) — (75 ) Amortization of intangibles and out-of-market contracts 52 29 — — 81 Amortization of unearned equity compensation — — 41 — 41 Gain on postretirement benefits curtailment — (21 ) — — (21 ) Loss on sale of assets — — 14 — 14 Impairment losses 4,655 400 31 — 5,086 Changes in derivative instruments 264 (31 ) — — 233 Changes in deferred income taxes and liability for uncertain tax benefits (1,092 ) (237 ) 2,655 — 1,326 Changes in nuclear decommissioning trust liability (2 ) — — — (2 ) Changes in collateral deposits supporting energy risk management activities (360 ) (21 ) — — (381 ) Cash (used)/provided by changes in other working capital (8,744 ) (847 ) 12,173 (2,840 ) (258 ) Net Cash (Used)/Provided by Operating Activities (6,928 ) (356 ) 8,593 — 1,309 Cash Flows from Investing Activities Dividends from NRG Yield, Inc. — — 70 (70 ) — Intercompany dividends — — 33 (33 ) — Acquisition of 2015 Drop Down Assets, net of cash acquired — (698 ) — 698 — Acquisition of businesses, net of cash acquired — (31 ) — — (31 ) Capital expenditures (316 ) (908 ) (59 ) — (1,283 ) (Increase)/decrease in restricted cash, net (1 ) 9 — — 8 Decrease in restricted cash - U.S. DOE projects — 34 1 — 35 Decrease in notes receivable — 18 — — 18 Proceeds from renewable energy grants — 82 — — 82 Purchases of emission allowances, net of proceeds 41 — — — 41 Investments in nuclear decommissioning trust fund securities (629 ) — — — (629 ) Proceeds from sales of nuclear decommissioning trust fund securities 631 — — — 631 Proceeds from sale of assets, net — 1 26 — 27 Investments in unconsolidated affiliates 1 (357 ) (39 ) — (395 ) Other — 11 — — 11 Net Cash (Used)/Provided by Investing Activities (273 ) (1,839 ) 32 595 (1,485 ) Cash Flows from Financing Activities Dividends from NRG Yield, Inc. — (70 ) — 70 — Intercompany dividends — (33 ) — 33 — Payments from/(for) intercompany loans 7,183 1,258 (8,441 ) — — Acquisition of 2015 Drop Down Assets, net of cash acquired — — 698 (698 ) — Payment of dividends to preferred stockholders — — (201 ) — (201 ) Net receipts from acquired derivatives that include financing elements — 196 — — 196 Payment for treasury stock — — (437 ) — (437 ) Distributions from, net of contributions to, noncontrolling interests in subsidiaries — 47 — — 47 Proceeds from sale of noncontrolling interests in subsidiaries — 600 — — 600 Proceeds from issuance of common stock — — 1 — 1 Proceeds from issuance of long-term debt — 953 51 — 1,004 Payments of short and long-term debt — (1,353 ) (246 ) — (1,599 ) Payment of debt issuance and hedging costs — (21 ) — — (21 ) Other — (22 ) — — (22 ) Net Cash Provided/(Used) by Financing Activities 7,183 1,555 (8,575 ) (595 ) (432 ) Effect of exchange rate changes on cash and cash equivalents — 10 — — 10 Net (Decrease)/Increase in Cash and Cash Equivalents (18 ) (630 ) 50 — (598 ) Cash and Cash Equivalents at Beginning of Period 18 1,455 643 — 2,116 Cash and Cash Equivalents at End of Period $ — $ 825 $ 693 $ — $ 1,518 (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, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net income $ 924 $ 426 $ 149 $ (1,367 ) $ 132 Adjustments to reconcile net income to net cash provided by operating activities: Distributions from unconsolidated affiliates — 87 — — 87 Equity in earnings of unconsolidated affiliates (13 ) (33 ) — 8 (38 ) Depreciation and amortization 801 706 16 — 1,523 Provision for bad debts 64 — — — 64 Amortization of nuclear fuel 46 — — — 46 Amortization of financing costs and debt discount/premiums — (40 ) 28 — (12 ) Adjustment to loss on debt extinguishment — 8 17 — 25 Amortization of intangibles and out-of-market contracts 65 (1 ) — — 64 Amortization of unearned equity compensation — — 42 — 42 Gain on sale of assets — (4 ) — — (4 ) Impairment losses — 119 — (22 ) 97 Changes in derivative instruments (149 ) 88 — — (61 ) Changes in deferred income taxes and liability for uncertain tax benefits 242 (115 ) (281 ) — (154 ) Changes in nuclear decommissioning trust liability 19 — — — 19 Changes in collateral deposits supporting energy risk management activities 101 45 — — 146 Cash provided/(used) by changes in other working capital 686 (958 ) (1,575 ) 1,381 (466 ) Net Cash Provided/(Used) by Operating Activities 2,786 328 (1,604 ) — 1,510 Cash Flows from Investing Activities Dividends from NRG Yield, Inc. — — 60 (60 ) — Acquisition of business, net of cash acquired — (25 ) (2,911 ) — (2,936 ) Capital expenditures (252 ) (619 ) (38 ) — (909 ) Decrease in restricted cash — 57 — — 57 (Increase)/decrease in restricted cash - U.S. DOE projects — (209 ) 3 — (206 ) Decrease in notes receivable — 25 — — 25 Proceeds from renewable energy grants — 916 — — 916 Purchases of emission allowances, net of proceeds (16 ) — — — (16 ) Investments in nuclear decommissioning trust fund securities (619 ) — — — (619 ) Proceeds from sales of nuclear decommissioning trust fund securities 600 — — — 600 Proceeds from sale of assets, net — — 203 — 203 Investments in unconsolidated affiliates, net — (25 ) (78 ) — (103 ) Other — 85 — — 85 Net Cash (Used)/Provided by Investing Activities (287 ) 205 (2,761 ) (60 ) (2,903 ) Cash Flows from Financing Activities Dividends from NRG Yield, Inc. — (60 ) — 60 — Payments (for)/from intercompany loans (2,523 ) (685 ) 3,208 — Payment for dividends to preferred stockholders — — (196 ) — (196 ) Net receipts from acquired derivatives that include financing elements — 9 — — 9 Payment for treasury stock — — (39 ) — (39 ) Distributions from, net of contributions to, noncontrolling interests in subsidiaries — 189 — — 189 Proceeds from sale of noncontrolling interests in subsidiaries — 630 — — 630 Proceeds from issuance of common stock — — 21 — 21 Proceeds from issuance of long-term debt — 1,182 3,381 — 4,563 Payments of short and long-term debt — (1,160 ) (2,667 ) — (3,827 ) Payment of debt issuance and hedging costs — (39 ) (28 ) — (67 ) Other (14 ) (4 ) — — (18 ) Net Cash (Used)/Provided by Financing Activities (2,537 ) 62 3,680 60 1,265 Effect of exchange rate changes on cash and cash equivalents — (10 ) — — (10 ) Net (Decrease)/Increase in Cash and Cash Equivalents (38 ) 585 (685 ) — (138 ) Cash and Cash Equivalents at Beginning of Period 56 870 1,328 — 2,254 Cash and Cash Equivalents at End of Period $ 18 $ 1,455 $ 643 $ — $ 2,116 (a) All significant intercompany transactions have been eliminated in consolidation.

VALUATION AND QUALIFYING ACCOUN

VALUATION AND QUALIFYING ACCOUNTS (Tables)	12 Months Ended
	Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]
Schedule of Valuation and Qualifying Accounts Disclosure	SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2016 , 2015 , and 2014 Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Deductions Balance at End of Period (In millions) Allowance for doubtful accounts, deducted from accounts receivable Year Ended December 31, 2016 $ 21 $ 48 $ — $ (39 ) (a) $ 30 Year Ended December 31, 2015 23 62 — (64 ) (a) 21 Year Ended December 31, 2014 40 64 — (81 ) (a) 23 Income tax valuation allowance, deducted from deferred tax assets Year Ended December 31, 2016 $ 3,575 $ 306 $ 235 $ — $ 4,116 Year Ended December 31, 2015 265 3,039 271 — 3,575 Year Ended December 31, 2014 291 — (10 ) (16 ) 265 (a) Represents principally net amounts charged as uncollectible.

Nature of Business (Details)

Nature of Business (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Power Generation Facilities
Current portion of long-term debt and capital leases	$ 1,220	$ 481
Cash and cash equivalents	1,973	1,518	$ 2,116	$ 2,254
Net Cash Provided by (Used in) Operating Activities	2,072	$ 1,309	$ 1,510
Genon [Member]
Power Generation Facilities
Cash and cash equivalents	$ 1,000
Percent of Total Assets	0.156
Percent of Total Liabilities	0.169
Net Cash Provided by (Used in) Operating Activities	$ 94
GenOn Mid-Atlantic, LLC [Member]
Power Generation Facilities
Cash and cash equivalents	471
REMA [Member]
Power Generation Facilities
Cash and cash equivalents	100
2017 [Member] | Genon [Member]
Power Generation Facilities
Current portion of long-term debt and capital leases	691
Debt Instrument, Unamortized Premium, Current	$ 8
Active [Member] | Approximation [Member]
Power Generation Facilities
Generation capacity (in MW) | MW	47,000
NRG Energy [Member] | Letter of Credit [Member] | Intercompany Credit Agreement [Member] | Genon [Member]
Power Generation Facilities
Line of Credit Facility, Remaining Borrowing Capacity	$ 228
Line of Credit Facility, Maximum Borrowing Capacity	$ 500

Nature of Business (Details 2 -

Nature of Business (Details 2 - Yield IPO) $ in Millions	Jul. 30, 2014USD ($)shares	Dec. 31, 2016shares	Dec. 31, 2015shares
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Common stock, shares outstanding		315,443,011	314,190,042
Class A Common Stock | NRG Yield, Inc. [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares, Issued	12,075,000
Proceeds from Issuance or Sale of Equity | $	$ 630
Public Shareholders [Member] | NRG Yield, Inc. [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Common Stock, Voting Interest		0.449
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		53.30%
NRG [Member] | NRG Yield, Inc. [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Common Stock, Voting Interest		0.551
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		46.70%

Summary of Significant Accoun67

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Summary of Significant Accounting Policies Disclosure
Finite-Lived Intangible Assets, Accumulated Amortization	$ 1,775,000,000	$ 1,525,000,000	[1]
Allowance for Doubtful Accounts Receivable, Current	30,000,000	21,000,000
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount	46,000,000	29,000,000		$ 19,000,000	$ 2,000,000
Redeemable Noncontrolling Interest, Distributions from Noncontrolling Interests	(1,000,000)
Redeemable Noncontrolling Interest, Cash Contributions from Noncontrolling Interest Holders	$ 56,000,000	27,000,000		36,000,000
Inventory Write-down		19,000,000
Funds Deposited by Counterparties
Number of months beyond which company can not predict the holding of collateral (in months)	12 months
Project Development Costs and Capitalized Interest
Amount of interest capitalized	$ 43,000,000	30,000,000		29,000,000
Income Taxes
Unrecognized tax benefits, more-likely-than-not threshold percentage	50.00%
Revenue Recognition
Energy revenues from resales of purchased power	$ 154,000,000	165,000,000		387,000,000
Unbilled revenues	321,000,000	309,000,000		341,000,000
Leases [Abstract]
Operating Leases, Income Statement, Contingent Revenue	936,000,000	777,000,000		544,000,000
Gross Receipts and Sales Taxes
Gross Receipts Tax	102,000,000	110,000,000		108,000,000
Cost of Energy for Retail Operations
Transmission and distribution charges not yet billed	90,000,000	85,000,000		86,000,000
Foreign Currency Translation and Transaction Gains and Losses
Cumulative translation adjustment	(11,000,000)	(10,000,000)		1,000,000
Tax Equity Arrangements [Abstract]
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	(38,000,000)	(17,000,000)		(19,000,000)
Marketing and Advertising Expense
Marketing and advertising expense	247,000,000	307,000,000		208,000,000
Advertising Expense	53,000,000	$ 135,000,000		$ 87,000,000
Indefinite-Lived Intangible Assets (Excluding Goodwill)	$ 0
South Texas Project
Property, Plant and Equipment
Ownership Interest (as a percent)	44.00%
Current Debt Service Payment [Member]
Summary of Significant Accounting Policies Disclosure
Restricted Cash and Cash Equivalents	$ 53,000,000
Operating Expense [Member]
Summary of Significant Accounting Policies Disclosure
Restricted Cash and Cash Equivalents	51,000,000
Distributions [Member]
Summary of Significant Accounting Policies Disclosure
Restricted Cash and Cash Equivalents	58,000,000
Reserves [Member]
Summary of Significant Accounting Policies Disclosure
Restricted Cash and Cash Equivalents	$ 284,000,000
[1]	Adjusted for write-off of fully amortized emission allowances of $154 million.

Business Acquisitions and Dis68

Business Acquisitions and Dispositions Business Acquisitions and Dispositions (2016 and 2015 Acquisitions) $ in Millions	Oct. 03, 2016USD ($)MW	Aug. 13, 2014USD ($)	Dec. 31, 2016USD ($)MW	Jun. 30, 2015USD ($)MW	Dec. 31, 2014USD ($)	Aug. 12, 2014USD ($)MW
SunEdison Utility-Scale Solar and Wind [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross			$ 124
Business Acquisitions, Consideration Transferred, Purchase Price			328
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other			5
Business Combination, Contingent Consideration, Liability			59
SunEdison Solar Distributed Generation [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	29
Payments to Acquire Businesses, Gross	$ 67
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			47
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles			$ 15
Desert Sunlight [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW				550
Payments to Acquire Businesses, Gross				$ 285
Percentage of Ownership				25.00%
Alta Wind Portfolio [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW						947
Payments to Acquire Businesses, Gross		$ 923
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt					$ 1,591
Business Acquisitions, Consideration Transferred, Purchase Price						$ 870
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					1,304
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles					1,177
Percentage of Ownership						100.00%
EME [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt					1,249
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other					724
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					2,438
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles					$ 172
Construction-ready solar facility [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW			154
Payments to Acquire Businesses, Gross			$ 11
Construction-ready and in-development solar assets [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW			110
Payments to Acquire Businesses, Gross			$ 2
In-development solar assets [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW			71
Mechanically-complete solar assets [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW			530
In-development wind assets [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross			$ 111
Remaining Lease Term			20 years
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt			$ 222
NRG [Member] | Mechanically-complete solar assets [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW			265
Post-closing obligations [Member] | SunEdison Solar Distributed Generation [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 5
Non Recourse Debt [Member] | Utah Portfolio [Member]
Business Acquisition [Line Items]
Additional Debt Borrowed			$ 65

Business Acquisitions and Dis69

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - Alta Wind (Details 2) $ in Millions	Aug. 13, 2014USD ($)	Jul. 30, 2014USD ($)shares	Aug. 11, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Aug. 12, 2014USD ($)MW	Aug. 05, 2014USD ($)
Business Acquisition [Line Items]
Long-term Debt				$ 19,406	$ 19,620
Alta Wind Portfolio [Member]
Business Acquisition [Line Items]
Percentage of Ownership							100.00%
Power Generation Capacity, Megawatts | MW							947
Payments to Acquire Businesses, Gross	$ 923
Business Acquisitions, Consideration Transferred, Purchase Price							$ 870
Business Acquisition, Consideration Transferred, Working Capital							$ 53
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents			$ 22			$ 22
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Cash			0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current and Non-Current Assets						49
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Other Assets			(2)
Business Acquisition, Purchase Price Allocation, Other Assets, Adjusted			47
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment						1,304
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment			6
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment, Adjusted			1,310
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles						1,177
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles			(6)
Business Acquisition, Purchase Price Allocation, Intangible Assets, Other than Goodwill, Adjusted			1,171
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets						2,552
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Total Assets			(2)
Business Acquisition, Purchase Price Allocation, Assets Acquired, Adjusted			2,550
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt						1,591
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncurrent Liabilities Longterm Debt			0
Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt, Adjusted			1,591
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current and Non-Current Liabilities						38
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Current and Noncurrent Liabilities			(2)
Business Acquisition, Purchase Price Allocation, Current and Non-current Liabilities, Adjusted			36
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities						1,629
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Liabilities			(2)
Business Acquisition, Purchase Price Allocation, Liabilities Assumed, Adjusted			1,627
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net						$ 923
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Net Assets Acquired			0
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net Adjusted			$ 923
Alta Wind I - V Lease financing arrangement [Member]
Business Acquisition [Line Items]
Lessor Leasing Arrangements, Operating Leases, Term of Contract	21 years
Alta Wind X and Alta Wind XI, due 2020 [Member]
Business Acquisition [Line Items]
Lessor Leasing Arrangements, Operating Leases, Term of Contract	22 years
NRG Yield, Inc. [Member] | Common Class A [Member]
Business Acquisition [Line Items]
Shares, Issued | shares		12,075,000
Proceeds from Issuance or Sale of Equity		$ 630
NRG Yield Operating LLC [Member]
Business Acquisition [Line Items]
Long-term Debt								$ 500
Debt Instrument, Interest Rate, Stated Percentage								5.375%

Business Acquisitions and Dis70

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - Dominion (Details 4) $ in Millions	Mar. 31, 2014USD ($)customer	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Goodwill		$ 662	$ 999
Business Acquisition, Goodwill, Expected Tax Deductible Amount		$ 547	$ 620
Dominion [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 192
Business Acquisitions, Consideration Transferred, Purchase Price	165
Business Acquisition, Consideration Transferred, Working Capital	27
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables	40
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other	14
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Derivative Assets	21
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	47
Goodwill	91
Business Acquisition, Goodwill, Expected Tax Deductible Amount	$ 8
Scenario, Plan [Member] | Dominion [Member]
Business Acquisition [Line Items]
Business Acquisition, Customers Acquired | customer	540,000
Customer Relationships [Member] | Dominion [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles	$ 64
Trade Names [Member] | Dominion [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	$ 9

Business Acquisitions and Dis71

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - EME 1 (Details 5) $ in Millions	Apr. 02, 2014USD ($)MWshares	Mar. 31, 2015USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 30, 2014	Apr. 30, 2014MW
Business Acquisition [Line Items]
Goodwill				$ 662	$ 999
EME [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt						$ 1,249
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents		$ 1,422				1,422
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Cash		0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current and Non-Current Assets						724
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Other Assets		72
Business Acquisition, Purchase Price Allocation, Other Assets, Adjusted		796
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment						2,438
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment		(3)
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment, Adjusted		2,435
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles						172
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles		0
Business Acquisition, Purchase Price Allocation, Intangible Assets, Other than Goodwill, Adjusted		172
Goodwill						334
Goodwill, Purchase Accounting Adjustments		(56)
Goodwill, Adjusted		278
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets						773
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncurrent Assets		0
Business Acquisition, Purchase Price Allocation, Noncurrent Assets, Adjusted		773
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets						5,863
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Total Assets		13
Business Acquisition, Purchase Price Allocation, Assets Acquired, Adjusted		5,876
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current and Non-Current Liabilities						629
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Current and Noncurrent Liabilities		13
Business Acquisition, Purchase Price Allocation, Current and Non-current Liabilities, Adjusted		642
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Out-of-market Contracts and Leases						159
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Out of Market Contracts and Leases		0
Business Acquisition, Purchase Price Allocation, Out of Market Contracts and Leases, Adjusted		159
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncurrent Liabilities Longterm Debt		0
Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt, Adjusted		1,249
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities						2,037
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Liabilities		13
Business Acquisition, Purchase Price Allocation, Liabilities Assumed, Adjusted		2,050
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value						352
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncontrolling Interest		0
Business Acquisition, Purchase Price Allocation, Noncontrolling Interest, Adjusted		352
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net						$ 3,474
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Net Assets Acquired		0
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net Adjusted		$ 3,474
Edison Mission Energy [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	8,000
Business Combination, Consideration Transferred	$ 3,500
Business Combination, Estimated Consideration Transferred, Estimated Liabilities Incurred	700
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	$ 1,200
Mission Del Sol [Member]
Business Acquisition [Line Items]
Percentage of Ownership							100.00%
Sunrise Facility [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW								586
Common Stock [Member] | Edison Mission Energy [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	12,671,977
Through 2034 [Member]
Business Acquisition [Line Items]
Repayments of Long-term Capital Lease Obligations			$ 405
EME [Member]
Business Acquisition [Line Items]
Goodwill				$ 276
Cogeneration facilities [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage								50.00%
Mission Del Sol [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage								50.00%

Business Acquisitions and Dis72

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - Potrero & EVgo (Details)	Sep. 26, 2016USD ($)	Jun. 18, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 17, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Litigation Settlement, Amount								$ 12,000,000
Gain (Loss) on Disposition of Other Assets						$ 224,000,000	$ (14,000,000)	$ 4,000,000
Equity Method Investments						1,120,000,000	$ 1,045,000,000
Potrero LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	$ 86,000,000
Gain (Loss) on Disposition of Property Plant Equipment			$ 74,000,000
EVgo [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses		$ 39,000,000
Capital Contributions From Partners in Equity Method Investment									$ 15,000,000
Future Capital Contributions From Partners in Equity Method Investment									$ 7,000,000
Future Revenue Rights		70,000,000
Gain (Loss) on Disposition of Other Assets				$ 78,000,000
Gain (Loss) on Disposition of Business				27,000,000
Cash [Member] | Potrero LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	74,000,000
Cash [Member] | EVgo [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses		17,000,000
Closing costs [Member] | Potrero LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	8,000,000
Post-closing obligations [Member] | Potrero LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	$ 4,000,000
Working Capital Adjustment [Member] | EVgo [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses		$ 2,500,000
CPUC [Member] | EVgo [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Litigation Settlement, Amount					$ 102,500,000
Loss Contingency, Number of Fast Charge Stations to Be Installed in California					200
Loss Contingency, Number of Parking Spaces Required					10,000
Loss Contingency Accrual				$ 56,000,000		$ 47,000,000
EVgo [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage						35.00%
Equity Method Investments						$ 5,000,000

Business Acquisitions and Dis73

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - Aurora, Rock, Seward, Shelby (Details) $ in Millions

Jul. 13, 2016USD ($)

May 13, 2016USD ($)

Mar. 02, 2016USD ($)

Feb. 03, 2016USD ($)

Nov. 25, 2015USD ($)

Nov. 10, 2015USD ($)

Sep. 30, 2016USD ($)

Jun. 30, 2016USD ($)MW

Mar. 31, 2016USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Jul. 12, 2016USD ($)

May 12, 2016MW

Feb. 02, 2016USD ($)

Nov. 24, 2015MW

Nov. 09, 2015MW

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Asset Impairment Charges

$ 918

$ 5,030

$ 97

Rockford [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Percentage of Ownership

100.00%

Proceeds from Sale of Property, Plant, and Equipment

$ 56

$ 55

Power Generation Capacity, Megawatts | MW

450

Asset Impairment Charges

$ 17

Base Residual Auction Results Adjustments

$ 1

Aurora Generating Station [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from Sale of Property, Plant, and Equipment

$ 369

$ 365

Power Generation Capacity, Megawatts | MW

878

Base Residual Auction Results Adjustments

$ 4

Gain (Loss) on Disposition of Property Plant Equipment

$ 188

Seward Generating Station [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from Sale of Property, Plant, and Equipment

$ 75

$ 75

Power Generation Capacity, Megawatts | MW

525

Asset Impairment Charges

$ 134

Disposal Group, Including Discontinued Operation, Cash

$ 3

Amount of Continuing Cash Flow After Disposition

5

Shelby County Energy Center, LLC [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from Sale of Property, Plant, and Equipment

$ 46

$ 46

Power Generation Capacity, Megawatts | MW

352

Gain (Loss) on Disposition of Property Plant Equipment

$ 29

Future Revenue Rights

10

Receipt of Future Revenue Rights

$ 8

Annual [Member] | Seward Generating Station [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Amount of Continuing Cash Flow After Disposition

1

Environmental Testing [Member] | Seward Generating Station [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Amount of Continuing Cash Flow After Disposition

$ 2.5

Robindale Energy Services, Inc [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Long-term Purchase Commitment, Amount

$ 13

Business Acquisitions and Dis74

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - 2015 & 2014 Dispositions (Details) $ in Millions	Dec. 03, 2014USD ($)	Jul. 07, 2014USD ($)	Sep. 30, 2014USD ($)MW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2016	Feb. 01, 2016USD ($)	Dec. 02, 2014MW	Jul. 03, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt				$ 19,406	$ 19,620
Debt Instrument, Description of Variable Rate Basis				3 month LIBOR
Petra Nova Parish Holdings [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
Power Generation Capacity, Megawatts | MW			75
Altenex [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage					32.00%
Sabine CoGen, LP [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Equity Method Investments	$ 35
Equity Method Investment, Realized Gain (Loss) on Disposal						$ 18
Percentage of Ownership Sold of Subsidiary									50.00%
Power Generation Capacity, Megawatts | MW									105
Altenex [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Equity Method Investments					$ 26
Equity Method Investment, Realized Gain (Loss) on Disposal					$ 14
Petra Nova Parish Holdings [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of Ownership Sold of Subsidiary										50.00%
Capital Contribution to Equity Method Investment		$ 35
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		$ 76
Capital Contributions From Partners in Equity Method Investment			$ 300
Percentage of Ownership			50.00%
Department of Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amount guaranteed to borrow by US DOE			$ 167
Additional US DOE funding								$ 23
JBIC and Mizuho [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt			250
NEXI Covered Loan [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt			$ 75
Debt Instrument, Description of Variable Rate Basis			LIBOR
Debt Instrument, Basis Spread on Variable Rate			1.75%
JBIC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt			$ 175
Debt Instrument, Description of Variable Rate Basis			LIBOR
Debt Instrument, Basis Spread on Variable Rate			0.50%
Debt Instrument, Incremental Escalation On Basis Spread, Percentage			1.50%
Design and Engineering Phase [Member] | Department of Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt			$ 7
Construction Phase [Member] | Department of Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt			$ 106

Business Acquisitions and Dis75

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - Transfer of Assets (Details) $ in Millions	Dec. 31, 2016USD ($)	Sep. 01, 2016USD ($)	Dec. 31, 2015USD ($)	Nov. 02, 2015USD ($)facilityMW	Jan. 02, 2015USD ($)	Jun. 30, 2014USD ($)
Business Acquisition [Line Items]
Long-term Debt	$ 19,406		$ 19,620
CVSR [Member]
Business Acquisition [Line Items]
Percentage of Ownership Sold of Subsidiary		51.05%
Consideration Paid for Sale of Assets Under Common Control		$ 78.5
ROFO Assets [Member]
Business Acquisition [Line Items]
Percentage of Ownership Sold of Subsidiary				75.00%
Consideration Paid for Sale of Assets Under Common Control				$ 209	$ 489	$ 357
Long-term Debt				$ 193	737	612
Number of Facilities | facility				12
Power Generation Capacity, Megawatts | MW				814
Consideration Paid for Sale of Assets Under Common Control, net of Working Capital Adjustments				$ 207
NRG Yield, Inc. [Member] | CVSR [Member]
Business Acquisition [Line Items]
Long-term Debt		$ 496
Financial Institutions [Member] | ROFO Assets [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value				159
Working Capital Adjustment [Member] | ROFO Assets [Member]
Business Acquisition [Line Items]
Consideration Paid for Sale of Assets Under Common Control				$ 2	$ 9	8
Base Purchase Price [Member] | ROFO Assets [Member]
Business Acquisition [Line Items]
Consideration Paid for Sale of Assets Under Common Control						$ 349

Fair Value of Financial Instr76

Fair Value of Financial Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Assets
Notes receivable (a)		$ 34	$ 73
Long-term Debt		19,406	19,620
Liabilities
Debt Instrument, Fair Value Disclosure	[1]	18,566	18,263
Level 2
Liabilities
Debt Instrument, Fair Value Disclosure		11,055	11,028
Level 3
Assets
Notes receivable (a)	[2]	34	73
Liabilities
Debt Instrument, Fair Value Disclosure		7,511	7,235
Carrying Amount
Assets
Notes receivable (a)	[2]	34	73
Long-term Debt	[1]	$ 19,406	$ 19,620
[1]	Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.
[2]	Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.

Fair Value of Financial Instr77

Fair Value of Financial Instruments (Recurring FV Measurements - Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2015
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	$ 1,251		$ 2,220
Derivative liabilities	1,378		2,214
Fair Value, Assets And Liabilities, Level 1 to Level 2 Transfers, Amount	0		0
Fair Value, Assets And Liabilities, Level 2 to Level 1 Transfers, Amount	0		0
Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	1,202		2,220
Derivative liabilities	1,290		2,086
Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	49
Derivative liabilities	88		128
Fair Value, Measurements, Recurring
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	17		17
Available-for-sale Securities	10		9
Other	10	[1]	14	[2]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value	1		1
Total assets	1,899		2,822
Total liabilities	1,378		2,214
Fair Value, Measurements, Recurring | Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	1,202		2,220
Derivative liabilities	1,290		2,086
Fair Value, Measurements, Recurring | Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	49
Derivative liabilities	88		128
Fair Value, Measurements, Recurring | Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments	25		6
Fair Value, Measurements, Recurring | U.S. government and federal agency obligations
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments	73		55
Fair Value, Measurements, Recurring | 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 | Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments	17		25
Fair Value, Measurements, Recurring | Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments	84		81
Fair Value, Measurements, Recurring | Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments	346		334
Fair Value, Measurements, Recurring | Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments	3		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	10		9
Other	10	[1]	14	[2]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value	1		1
Total assets	969		986
Total liabilities	494		868
Fair Value, Measurements, Recurring | Level 1 | Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	559		622
Derivative liabilities	494		868
Fair Value, Measurements, Recurring | Level 1 | Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	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	25		6
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	72		54
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	292		280
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		0
Other	0	[1]	0	[2]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value	0		0
Total assets	767		1,616
Total liabilities	723		1,164
Fair Value, Measurements, Recurring | Level 2 | Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	551		1,449
Derivative liabilities	635		1,036
Fair Value, Measurements, Recurring | Level 2 | Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	49
Derivative liabilities	88		128
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	1		1
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	17		25
Fair Value, Measurements, Recurring | Level 2 | Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments	84		81
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	3		1
Fair Value, Measurements, Recurring | Level 3
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	17		17
Available-for-sale Securities	0		0
Other	0	[1]	0	[2]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value	0		0
Total assets	163		220
Total liabilities	161		182
Fair Value, Measurements, Recurring | Level 3 | Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	92		149
Derivative liabilities	161		182
Fair Value, Measurements, Recurring | Level 3 | Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	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	54		54
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
[1]	Consists primarily of mutual funds held in a rabbi trust for non-qualified deferred compensation plans for certain key and highly compensated employees and a total return swap that does not meet the definition of a derivative.
[2]	Primarily consists of mutual funds held in a rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative.

Fair Value of Financial Instr78

Fair Value of Financial Instruments (Level 3 Inputs Recon - Details 3) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		$ 1,251		$ 2,220
Level 3
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		38		161
Total gains/(losses) realized/unrealized:
Included in earnings		12		(112)
Included in nuclear decommissioning obligations		(1)		(2)
Purchases		(28)		(15)
Transfers into Level 3		(18)	[1]	3	[2]
Transfers out of Level 3		(1)	[1]	3	[2]
Balance at the end of the period		2		38
(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		(14)		(30)
Derivative [Member] | Level 3
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		(33)	[3]	80	[4]
Total gains/(losses) realized/unrealized:
Included in earnings		12	[3]	(100)	[4]
Included in nuclear decommissioning obligations		0	[3]	0	[4]
Purchases		(29)	[3]	(19)	[4]
Transfers into Level 3		(18)	[1],[3]	3	[2],[4]
Transfers out of Level 3		(1)	[1],[3]	3	[2],[4]
Balance at the end of the period	[3]	(69)		(33)
(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		(14)	[3]	(30)	[4]
Trust Fund Investment [Member] | Level 3
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		54		52
Total gains/(losses) realized/unrealized:
Included in earnings		0		0
Included in nuclear decommissioning obligations		(1)		(2)
Purchases		1		4
Transfers into Level 3		0	[1]	0	[2]
Transfers out of Level 3		0	[1]	0	[2]
Balance at the end of the period		54		54
(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
Other Financial Instrument [Member] | Level 3
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		0		11
Total gains/(losses) realized/unrealized:
Included in earnings				(11)
Included in nuclear decommissioning obligations				0
Purchases				0
Transfers into Level 3	[2]			0
Transfers out of Level 3	[2]			0
Balance at the end of the period				0
(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
Debt Securities [Member] | Level 3
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		17		18
Total gains/(losses) realized/unrealized:
Included in earnings		0		(1)
Included in nuclear decommissioning obligations		0		0
Purchases		0		0
Transfers into Level 3		0	[1]	0	[2]
Transfers out of Level 3		0	[1]	0	[2]
Balance at the end of the period		17		17
(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
Commodity contracts
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		1,202		2,220
Commodity contracts | Fair Value, Measurements, Recurring [Member]
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		1,202		2,220
Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		92		149
Commodity contracts | Coal Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		0		0
Commodity contracts | Financial Transmission Rights [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		52		63
Commodity contracts | Power Contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		$ 40		$ 86
[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]	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.
[3]	Consists of derivatives assets and liabilities, net.
[4]	Consists of derivatives assets and liabilities, net.

Fair Value of Financial Instr79

Fair Value of Financial Instruments Fair Value of Financial Instruments (Derivative Fair Value Measurement - Details 4) $ in Millions	Dec. 31, 2016USD ($)$ / T$ / MWh	Dec. 31, 2015USD ($)$ / T$ / MWh
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value Determined Using Valuation Techniques, Percentage	7.00%
Derivative Liability, Fair Value Determined Using Valuation Techniques, Percentage	12.00%
Fair Value Assets, Measured on Recurring Basis, Valuation Techniques, Impact of Credit Reserve to Fair Value	$ 11	$ 5
Fair Value Assets Measured On Recurring Basis Valuation Techniques Impact Of Credit Reserve To Fair Value Included In Oci Derivative Contracts	2
Fair Value Assets, Measured on Recurring Basis, Valuation Techniques, Impact of Credit Reserve to Fair Value Included in Operating Revenues and Cost of Operations, Derivative Contracts	3
Derivative Asset, Fair Value, Gross Asset	1,251	2,220
Derivative Liability, Fair Value, Gross Liability	1,378	2,214
Derivative, Collateral, Right to Reclaim Cash	203	568
Cash collateral received in support of energy risk management activities	2	106
Commodity contracts
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,202	2,220
Derivative Liability, Fair Value, Gross Liability	1,290	2,086
Derivative, Collateral, Right to Reclaim Cash	14	271
Cash collateral received in support of energy risk management activities	1	113
Commodity contracts | Fair Value, Measurements, Recurring [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,202	2,220
Derivative Liability, Fair Value, Gross Liability	1,290	2,086
Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	92	149
Derivative Liability, Fair Value, Gross Liability	161	182
Power Contracts | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	40	86
Derivative Liability, Fair Value, Gross Liability	$ 107	$ 100
Power Contracts | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Minimum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / MWh	11,000,000	10,000,000
Power Contracts | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Maximum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / MWh	104,000,000	92,000,000
Power Contracts | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Weighted Average [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / MWh	31,000,000	27,000,000
Coal Contract [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 0	$ 0
Derivative Liability, Fair Value, Gross Liability	$ 1	$ 12
Coal Contract [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Minimum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / T	42,000,000	28,000,000
Coal Contract [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Maximum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / T	51,000,000	45,000,000
Coal Contract [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Weighted Average [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / T	45,000,000	35,000,000
Financial Transmission Rights [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 52	$ 63
Derivative Liability, Fair Value, Gross Liability	$ 53	$ 70
Financial Transmission Rights [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Minimum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Auction Price | $ / MWh	(22,000,000)	(98,000,000)
Financial Transmission Rights [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Maximum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Auction Price | $ / MWh	17,000,000	87,000,000
Financial Transmission Rights [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Weighted Average [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Auction Price | $ / MWh	0	0

Fair Value of Financial Instr80

Fair Value of Financial Instruments (Credit Risk - Details 5) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Fair Value Meaurements and Concentration of Credit Risk
Counterparty credit exposure, excluding credit risk exposure under certain long term agreements		$ 231
Counterparty credit exposure, collateral held (cash and letters of credit) against positions		2
Counterparty credit exposure, net		$ 229
Company's exposure before collateral expected to roll off by the end of 2015 (as a percent)		95.00%
Net exposure (as a percent)	[1],[2]	100.00%
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		$ 80
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		$ 4,100
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
Provision for bad debts		$ 48	$ 64	$ 64
Investment grade
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1],[2]	67.00%
External Credit Rating, Non Investment Grade [Member]
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1],[2]	33.00%
Utilities, energy merchants, marketers and other
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1],[2]	100.00%
NRG Yield, Inc. [Member]
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		$ 2,600
[1]	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.
[2]	The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.

Accounting for Derivative Ins81

Accounting for Derivative Instruments and Hedging Activities (Details) bbl in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MWhMMBTUTbbl	Dec. 31, 2015USD ($)MWhMMBTUTbbl
Fair value of the derivative instrument
Derivative assets	$ 1,251	$ 2,220
Derivative liabilities	1,378	2,214
Derivatives Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	12	0
Derivative liabilities	69	110
Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	1,239	2,220
Derivative liabilities	1,309	2,104
Interest rate contracts current | Derivatives Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	0	0
Derivative liabilities	28	42
Interest rate contracts current | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	0	0
Derivative liabilities	7	5
Interest rate contracts long-term | Derivatives Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	12	0
Derivative liabilities	41	68
Interest rate contracts long-term | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	37	0
Derivative liabilities	12	13
Commodity contracts current | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	1,062	1,915
Derivative liabilities	1,049	1,674
Commodity contracts long-term | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	140	305
Derivative liabilities	$ 241	$ 412
Emissions [Member] | Short Ton
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Mass | T	0	1
Equity [Member] | Shares [Member]
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Notional Amount	$ 1	$ 1
Interest [Member] | Dollars
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Notional Amount	$ 3,429	$ 2,326
Coal [Member] | Short Ton
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Mass | T	41	35
Natural Gas [Member] | MMbtu
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	85	293
Oil [Member] | Barrel
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Volume | bbl	1	1
Power [Member] | MWh
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	(28)	(74)
Short [Member] | MW/Day [Member] | Capacity [Member]
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	(1)	(1)

Accounting for Derivative Ins82

Accounting for Derivative Instruments and Hedging Activities (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Gain (Loss) on Cash Flow Hedge Ineffectiveness, Net	$ 0	$ 0	$ 0
Derivative assets	1,251	2,220
Cash Collateral (Held)	(2)	(106)
Gross Amounts of Recognized Derivative Liabilities	(1,378)	(2,214)
Cash collateral posted in support of energy risk management activities	203	568
Gross Amounts of Recognized Assets / Liabilities	(127)	6
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	13	158
Net Amount	(114)	164
Commodity contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	1,202	2,220
Derivative Instruments	(1,005)	(1,616)
Cash Collateral (Held)	(1)	(113)
Net Amount	196	491
Gross Amounts of Recognized Derivative Liabilities	(1,290)	(2,086)
Derivative Instruments	1,005	1,616
Cash collateral posted in support of energy risk management activities	14	271
Net Amount	(271)	(199)
Gross Amounts of Recognized Assets / Liabilities	(88)	134
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	13	158
Net Amount	(75)	292
Interest rate contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	49
Derivative Instruments	(4)
Cash Collateral (Held)	0
Net Amount	45
Gross Amounts of Recognized Derivative Liabilities	(88)	(128)
Derivative Instruments	4	0
Cash collateral posted in support of energy risk management activities	0	0
Net Amount	(84)	$ (128)
Gross Amounts of Recognized Assets / Liabilities	(39)
Derivative Instruments	0
Cash Collateral (Held) / Posted	0
Net Amount	$ (39)

Accounting for Derivative Ins83

Accounting for Derivative Instruments and Hedging Activities (Details 3) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income
Accumulated OCI beginning balance			$ (101)	$ (68)	$ (23)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			21	15	13
Mark-to-market of cash flow hedge accounting contracts			14	(48)	(58)
Accumulated OCI ending balance, net of tax			(66)	(101)	(68)
Accumulated OCI ending balance, tax			16	16	35
Losses expected to be realized from OCI during the next 12 months, net of $3 tax			(16)
Gains/(losses) expected to be realized from OCI during the next 12 months, tax			4
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges			(245)	(275)	(15)
Reversal of acquired gain positions related to economic hedges			(60)	(106)	(333)
Net unrealized gains on open positions related to economic hedges			20	9	361
Losses on ineffectiveness associated with open positions treated as cash flow hedges			0	0	0
Total unrealized mark-to-market (losses)/gains for economic hedging activities			(285)	(372)	13
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity			10	(46)	1
Reversal of Previously Unrecognized Unrealized Gain Loss Acquired as Part of Acquisition Trading Activity			0	(14)	(32)
Net unrealized gains/(losses) on open positions related to trading activity			18	(16)	45
Total unrealized mark-to-market gains/(losses) for trading activity			28	(76)	14
Total unrealized (losses)/gains			(257)	(448)	27
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains			(257)	(448)	27
Credit Risk Related Contingent Features
Collateral required for contracts with adequate assurance clauses in net liability positions			36
Collateral required for contracts with credit rating contingent features			56
Collateral due on net liability position that has not been called by a certain marginable agreement counterparty			14
Realized Gain [Member]
Unrealized mark-to-market results
Derivative Instruments Not Designated as Hedging Instruments, Gain	$ 98	$ 38
Energy commodities
Accumulated Other Comprehensive Income
Accumulated OCI beginning balance			0	(1)	(1)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net				1	0
Mark-to-market of cash flow hedge accounting contracts				0	0
Accumulated OCI ending balance, net of tax				0	(1)
Unrealized mark-to-market results
Total unrealized (losses)/gains			(257)	(448)	27
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains			(257)	(448)	27
Energy commodities | Unrealized (losses)/gains included in operating revenues
Unrealized mark-to-market results
Total unrealized (losses)/gains			(837)	(320)	515
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains			(837)	(320)	515
Energy commodities | Unrealized gains/(losses) included in cost of operations
Unrealized mark-to-market results
Total unrealized (losses)/gains			580	(128)	(488)
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains			580	(128)	(488)
Interest rate contracts
Accumulated Other Comprehensive Income
Accumulated OCI beginning balance			(101)	(67)	(22)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			21	14	13
Mark-to-market of cash flow hedge accounting contracts			14	(48)	(58)
Accumulated OCI ending balance, net of tax			(66)	(101)	(67)
Losses expected to be realized from OCI during the next 12 months, net of $3 tax			(16)
Unrealized mark-to-market results
Total unrealized (losses)/gains			36	17	(31)
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains			$ 36	17	$ (31)
NRG Solar Dandan [Member] | Interest rate contracts
Discontinuation of Cash Flow Hedge [Abstract]
Loss previously deferred in OCI recognized in earnings resulting from discontinued cash flow hedge accounting				$ 6
2016 [Member] | Realized Gain [Member]
Unrealized mark-to-market results
Derivative Instruments Not Designated as Hedging Instruments, Gain		18
2017 [Member] | Realized Gain [Member]
Unrealized mark-to-market results
Derivative Instruments Not Designated as Hedging Instruments, Gain	82	19
2018 [Member] | Realized Gain [Member]
Unrealized mark-to-market results
Derivative Instruments Not Designated as Hedging Instruments, Gain	13	$ 1
2019 [Member] | Realized Gain [Member]
Unrealized mark-to-market results
Derivative Instruments Not Designated as Hedging Instruments, Gain	$ 3

Nuclear Decommissioning Trust84

Nuclear Decommissioning Trust Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Nuclear decommissioning trust fund disclosure
Fair Value	$ 610	$ 561
Unrealized Gains	217	202
Unrealized Losses	4	3
Proceeds from sales of available-for-sale securities and the related realized gains and losses
Realized gains	26	21	$ 29
Realized losses	(11)	(14)	(8)
Proceeds from sale of securities	(510)	(631)	$ (600)
Cash and cash equivalents
Nuclear decommissioning trust fund disclosure
Fair Value	25	6
Unrealized Gains	0	0
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	0 years	0 years
U.S. government and federal agency obligations
Nuclear decommissioning trust fund disclosure
Fair Value	$ 73	$ 55
Unrealized Gains	1	1
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	11 years	11 years
Federal agency mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 62	$ 59
Unrealized Gains	1	1
Unrealized Losses	$ 1	$ 0
Weighted- average maturities (in years)	25 years	25 years
Commercial mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 17	$ 25
Unrealized Gains	0	0
Unrealized Losses	$ 1	$ 2
Weighted- average maturities (in years)	26 years	28 years
Corporate debt securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 84	$ 81
Unrealized Gains	1	1
Unrealized Losses	$ 2	$ 1
Weighted- average maturities (in years)	11 years	10 years
Equity securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 346	$ 334
Unrealized Gains	214	199
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	0 years	0 years
Foreign government fixed income securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 3	$ 1
Unrealized Gains	0	0
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	9 years	9 years
South Texas Project
Nuclear decommissioning trust fund disclosure
Ownership Interest (as a percent)	44.00%

Inventory (Details)

Inventory (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Inventory Disclosure [Abstract]
Fuel oil	$ 312	$ 289
Coal/Lignite	471	334
Natural gas	12	28
Spare parts	437	413
Other	20	47
Total Inventory	1,252	$ 1,111
Inventory Write-down	$ 19

Notes Receivable (Details)

Notes Receivable (Details) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Notes Receivable
Notes receivable (a)		$ 34	$ 73
Notes receivable, current	[1]	17	20
Notes receivable, noncurrent		$ 17	$ 53
[1]	The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

Property, Plant and Equipment87

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment
Accumulated Depreciation, Depletion and Amortization, Property, Plant and Equipment, Period Increase (Decrease)		$ 1,000
Total property, plant and equipment	$ 24,226	24,493
Construction in Progress, Gross	697	627
Accumulated depreciation	(6,314)	(5,761)
Net Property, Plant and Equipment	17,912	18,732
Facilities and equipment
Property, Plant and Equipment
Total property, plant and equipment	21,445	21,633
Land and improvements
Property, Plant and Equipment
Total property, plant and equipment	1,026	1,226
Nuclear fuel
Property, Plant and Equipment
Total property, plant and equipment	$ 601	545
Depreciable lives (in years)	5 years
Office furnishings and equipment
Property, Plant and Equipment
Total property, plant and equipment	$ 457	$ 462
Minimum [Member] | Facilities and equipment
Property, Plant and Equipment
Depreciable lives (in years)	1 year
Minimum [Member] | Office furnishings and equipment
Property, Plant and Equipment
Depreciable lives (in years)	2 years
Maximum [Member] | Facilities and equipment
Property, Plant and Equipment
Depreciable lives (in years)	40 years
Maximum [Member] | Office furnishings and equipment
Property, Plant and Equipment
Depreciable lives (in years)	10 years

Asset Impairments (Details)

Asset Impairments (Details) $ in Millions

Jul. 13, 2016USD ($)

May 13, 2016USD ($)

Feb. 03, 2016USD ($)

Nov. 25, 2015USD ($)

Dec. 31, 2016USD ($)

Jun. 30, 2016USD ($)

Mar. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)MW

Sep. 30, 2014USD ($)MW

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)MW

Sep. 30, 2016

May 12, 2016MW

Nov. 24, 2015MW

Dec. 31, 2009MW

Asset Impairments

Impairment losses

$ 918

$ 5,030

$ 97

Other Asset Impairment Charges

48

Emission Allowances [Member]

Asset Impairments

Impairment losses

$ 23

Mandalay operating unit [Member]

Asset Impairments

Impairment losses

$ 16

Ormond Beach operating unit [Member]

Asset Impairments

Impairment losses

28

43

Elbow Creek [Member]

Asset Impairments

Impairment losses

117

Goat Wind [Member]

Asset Impairments

Impairment losses

60

Forward [Member]

Asset Impairments

Impairment losses

6

Long Beach [Member]

Asset Impairments

Impairment losses

36

Conemaugh [Member]

Asset Impairments

Impairment losses

97

Keystone [Member]

Asset Impairments

Impairment losses

10

Pittsburg [Member]

Asset Impairments

Impairment losses

20

Other Intangible Assets [Member]

Asset Impairments

Impairment losses

23

Solar Panels [Member]

Asset Impairments

Impairment losses

19

$ 10

Deferred Marketing Expenses [Member]

Asset Impairments

Impairment losses

18

Other [Member]

Asset Impairments

Impairment losses

153

Limestone [Member]

Asset Impairments

Impairment losses

$ 1,514

W.A. Parish [Member]

Asset Impairments

Impairment losses

$ 1,295

Huntley [Member]

Asset Impairments

Impairment losses

132

Dunkirk [Member]

Asset Impairments

Impairment losses

160

Gregory Power Partners, L.P. [Member]

Asset Impairments

Impairment losses

176

Coolwater [Member]

Asset Impairments

Impairment losses

$ 22

Osceola facility [Member]

Asset Impairments

Impairment losses

$ 60

Coolwater [Member]

Asset Impairments

Power Generation Capacity, Megawatts | MW

636

636

Solar Panels [Member]

Asset Impairments

Impairment losses

29

Other [Member]

Asset Impairments

Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net

$ 22

Petra Nova Parish Holdings [Member]

Asset Impairments

Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net

$ 140

Equity Method Investment, Ownership Percentage

50.00%

Power Generation Capacity, Megawatts | MW

75

Community Wind North, LLC [Member]

Asset Impairments

Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net

36

Sherbino I Wind Farm LLC [Member]

Asset Impairments

Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net

$ 70

Equity Method Investment, Ownership Percentage

50.00%

Power Generation Capacity, Megawatts | MW

150

Osceola facility [Member]

Asset Impairments

Power Generation Capacity, Megawatts | MW

463

Rockford [Member]

Asset Impairments

Percentage of Ownership

100.00%

Proceeds from Sale of Property, Plant, and Equipment

$ 56

$ 55

Impairment losses

$ 17

Power Generation Capacity, Megawatts | MW

450

Seward Generating Station [Member]

Asset Impairments

Proceeds from Sale of Property, Plant, and Equipment

$ 75

$ 75

Impairment losses

$ 134

Power Generation Capacity, Megawatts | MW

525

Goodwill and Other Intangible89

Goodwill and Other Intangibles (Goodwill - Details 1) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2006USD ($)
Goodwill and Other Intangibles
Goodwill	$ 662	$ 999
Goodwill deductible for U.S. income tax purposes	547	620
Goodwill, Impairment Loss		1,500
Texas Genco
Goodwill and Other Intangibles
Goodwill in connection with acquisition			$ 1,700
Texas [Member]
Goodwill and Other Intangibles
Goodwill, Impairment Loss	$ 337	$ 1,400
Reporting Unit, Percentage of Carrying Amount in Excess of Fair Value	0.43	0.76
Home Solar [Member]
Goodwill and Other Intangibles
Goodwill, Impairment Loss		$ 125
Goal Zero [Member]
Goodwill and Other Intangibles
Goodwill, Impairment Loss		$ 36
EME [Member]
Goodwill and Other Intangibles
Goodwill	$ 276
Retail [Member]
Goodwill and Other Intangibles
Goodwill	341
Other [Member]
Goodwill and Other Intangibles
Goodwill	45
Texas [Member]
Goodwill and Other Intangibles
Goodwill	$ 0

Goodwill and Other Intangible90

Goodwill and Other Intangibles Goodwill and Other Intangibles - (Intangibles - Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	$ 3,811	$ 3,835		$ 3,969
Finite-Lived Intangible Assets, Purchases	84	137
Finite-lived Intangible Assets Acquired	18
Finite-Lived Intangible Assets, Usage	(45)	95
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	10	(154)
Impairment of Intangible Assets, Finite-lived	64	11
Finite-Lived Intangible Assets, Other Changes	(7)	11
Finite-Lived Intangible Assets, Accumulated Amortization	1,775	1,525	[1]
Finite-Lived Intangible Assets, Net	2,036	2,310
Amortization of Intangible Assets	278	277		268
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	198
Finite-Lived Intangible Assets, Amortization Expense, Year Two	136
Finite-Lived Intangible Assets, Amortization Expense, Year Three	129
Finite-Lived Intangible Assets, Amortization Expense, Year Four	112
Finite-Lived Intangible Assets, Amortization Expense, Year Five	110
Other Assets, Noncurrent, Emission Allowances	39
Emission Allowances [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	929	920		1,018
Finite-Lived Intangible Assets, Purchases	50	77
Finite-lived Intangible Assets Acquired	0
Finite-Lived Intangible Assets, Usage	(1)	(33)
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	10	154
Impairment of Intangible Assets, Finite-lived	23	0
Finite-Lived Intangible Assets, Other Changes	(7)	12
Finite-Lived Intangible Assets, Accumulated Amortization	605	502	[1]
Finite-Lived Intangible Assets, Net	324	418
Amortization of Intangible Assets	113	99		124
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	82
Finite-Lived Intangible Assets, Amortization Expense, Year Two	33
Finite-Lived Intangible Assets, Amortization Expense, Year Three	31
Finite-Lived Intangible Assets, Amortization Expense, Year Four	16
Finite-Lived Intangible Assets, Amortization Expense, Year Five	16
Energy Supply Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	54	54		54
Finite-Lived Intangible Assets, Purchases	0	0
Finite-lived Intangible Assets Acquired	0
Finite-Lived Intangible Assets, Usage	0	0
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	0	0
Impairment of Intangible Assets, Finite-lived	0	0
Finite-Lived Intangible Assets, Other Changes	0	0
Finite-Lived Intangible Assets, Accumulated Amortization	54	47	[1]
Finite-Lived Intangible Assets, Net	0	7
Amortization of Intangible Assets	7	5		6
Fuel Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	72	72		72
Finite-Lived Intangible Assets, Purchases	0	0
Finite-lived Intangible Assets Acquired	0
Finite-Lived Intangible Assets, Usage	0	0
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	0	0
Impairment of Intangible Assets, Finite-lived	0	0
Finite-Lived Intangible Assets, Other Changes	0	0
Finite-Lived Intangible Assets, Accumulated Amortization	67	65	[1]
Finite-Lived Intangible Assets, Net	5	7
Amortization of Intangible Assets	2	2		2
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	1
Finite-Lived Intangible Assets, Amortization Expense, Year Two	0
Finite-Lived Intangible Assets, Amortization Expense, Year Three	0
Finite-Lived Intangible Assets, Amortization Expense, Year Four	0
Finite-Lived Intangible Assets, Amortization Expense, Year Five	0
Customer Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	16	16		16
Finite-Lived Intangible Assets, Purchases	0	0
Finite-lived Intangible Assets Acquired	0
Finite-Lived Intangible Assets, Usage	0	0
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	0	0
Impairment of Intangible Assets, Finite-lived	0	0
Finite-Lived Intangible Assets, Other Changes	0	0
Finite-Lived Intangible Assets, Accumulated Amortization	8	6	[1]
Finite-Lived Intangible Assets, Net	8	10
Amortization of Intangible Assets	2	2		0
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	1
Finite-Lived Intangible Assets, Amortization Expense, Year Two	1
Finite-Lived Intangible Assets, Amortization Expense, Year Three	1
Finite-Lived Intangible Assets, Amortization Expense, Year Four	1
Finite-Lived Intangible Assets, Amortization Expense, Year Five	1
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	816	834		831
Finite-Lived Intangible Assets, Purchases	0	3
Finite-lived Intangible Assets Acquired	0
Finite-Lived Intangible Assets, Usage	0	0
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	0	0
Impairment of Finite-Lived Intangible Assets Accumulated Amortization	10
Impairment of Intangible Assets, Finite-lived	18	0
Impairment of Intangible Assets, Finite-Lived, Net	8
Finite-Lived Intangible Assets, Other Changes	0	0
Finite-Lived Intangible Assets, Accumulated Amortization	663	624	[1]
Finite-Lived Intangible Assets, Net	153	210
Amortization of Intangible Assets	49	67		70
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	26
Finite-Lived Intangible Assets, Amortization Expense, Year Two	14
Finite-Lived Intangible Assets, Amortization Expense, Year Three	10
Finite-Lived Intangible Assets, Amortization Expense, Year Four	8
Finite-Lived Intangible Assets, Amortization Expense, Year Five	6
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Impairment of Finite-Lived Intangible Assets Accumulated Amortization	8
Impairment of Intangible Assets, Finite-Lived, Net	15
Marketing Partnerships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	88	88		88
Finite-Lived Intangible Assets, Purchases	0	0
Finite-lived Intangible Assets Acquired	0
Finite-Lived Intangible Assets, Usage	0	0
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	0	0
Impairment of Intangible Assets, Finite-lived	0	0
Finite-Lived Intangible Assets, Other Changes	0	0
Finite-Lived Intangible Assets, Accumulated Amortization	49	41	[1]
Finite-Lived Intangible Assets, Net	39	47
Amortization of Intangible Assets	8	14		15
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	5
Finite-Lived Intangible Assets, Amortization Expense, Year Two	5
Finite-Lived Intangible Assets, Amortization Expense, Year Three	4
Finite-Lived Intangible Assets, Amortization Expense, Year Four	4
Finite-Lived Intangible Assets, Amortization Expense, Year Five	4
Trade Names [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	342	342		353
Finite-Lived Intangible Assets, Purchases	0	0
Finite-lived Intangible Assets Acquired	0
Finite-Lived Intangible Assets, Usage	0	0
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	0	0
Impairment of Intangible Assets, Finite-lived	0	6
Finite-Lived Intangible Assets, Other Changes	0	(5)
Finite-Lived Intangible Assets, Accumulated Amortization	159	137	[1]
Finite-Lived Intangible Assets, Net	183	205
Amortization of Intangible Assets	22	23		21
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	23
Finite-Lived Intangible Assets, Amortization Expense, Year Two	23
Finite-Lived Intangible Assets, Amortization Expense, Year Three	23
Finite-Lived Intangible Assets, Amortization Expense, Year Four	23
Finite-Lived Intangible Assets, Amortization Expense, Year Five	23
PPA [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	1,264	1,264		1,270
Finite-Lived Intangible Assets, Purchases	0	0
Finite-lived Intangible Assets Acquired	0
Finite-Lived Intangible Assets, Usage	0	0
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	0	0
Impairment of Intangible Assets, Finite-lived	0	0
Finite-Lived Intangible Assets, Other Changes	0	(6)
Finite-Lived Intangible Assets, Accumulated Amortization	138	75	[1]
Finite-Lived Intangible Assets, Net	1,126	1,189
Amortization of Intangible Assets	63	50		24
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	57
Finite-Lived Intangible Assets, Amortization Expense, Year Two	57
Finite-Lived Intangible Assets, Amortization Expense, Year Three	57
Finite-Lived Intangible Assets, Amortization Expense, Year Four	57
Finite-Lived Intangible Assets, Amortization Expense, Year Five	57
Other Finite Lived Intangible Assets Member
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	230	245		267
Finite-Lived Intangible Assets, Purchases	34	57
Finite-lived Intangible Assets Acquired	18
Finite-Lived Intangible Assets, Usage	(44)	(62)
Finite-Lived Intangible Assets, Write-off of Fully Amortized Intangible Assets	0	0
Impairment of Intangible Assets, Finite-lived	23	5
Finite-Lived Intangible Assets, Other Changes	0	(12)
Finite-Lived Intangible Assets, Accumulated Amortization	32	28	[1]
Finite-Lived Intangible Assets, Net	198	217
Amortization of Intangible Assets	12	$ 15		$ 6
Finite-Lived Intangible Assets, Net - 5 year Amortization [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	3
Finite-Lived Intangible Assets, Amortization Expense, Year Two	3
Finite-Lived Intangible Assets, Amortization Expense, Year Three	3
Finite-Lived Intangible Assets, Amortization Expense, Year Four	3
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$ 3
[1]	Adjusted for write-off of fully amortized emission allowances of $154 million.

Goodwill and Other Intangible91

Goodwill and Other Intangibles Goodwill and Other Intangibles - (OOM - Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Apr. 02, 2014	Dec. 14, 2012
Finite-Lived Intangible Assets [Line Items]
Off-market Lease, Unfavorable	$ 1,040	$ 1,146
Accumulated Amortization of Out of Market Contracts	765	$ 664
EME [Member] | Lease Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Off-market Lease, Unfavorable			$ 159
GenOn Energy [Member] | Lease Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Off-market Lease, Unfavorable				$ 790
GenOn Energy [Member] | Gas Transportation Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Off-market Lease, Unfavorable				$ 327
Out of Market Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Future Amortization Expenses, Out-of-Market Contracts, Year One	100
Future Amortization Expenses, Out-of-Market Contracts, Year Two	95
Future Amortization Expenses, Out-of-Market Contracts, Year Three	93
Future Amortization Expenses, Out-of-Market Contracts, Year Four	93
Future Amortization Expenses, Out-of-Market Contracts, Year Five	83
Out of Market Contracts [Member] | Power Contracts
Finite-Lived Intangible Assets [Line Items]
Future Amortization Expenses, Out-of-Market Contracts, Year One	16
Future Amortization Expenses, Out-of-Market Contracts, Year Two	16
Future Amortization Expenses, Out-of-Market Contracts, Year Three	17
Future Amortization Expenses, Out-of-Market Contracts, Year Four	17
Future Amortization Expenses, Out-of-Market Contracts, Year Five	10
Out of Market Contracts [Member] | Lease Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Future Amortization Expenses, Out-of-Market Contracts, Year One	47
Future Amortization Expenses, Out-of-Market Contracts, Year Two	47
Future Amortization Expenses, Out-of-Market Contracts, Year Three	47
Future Amortization Expenses, Out-of-Market Contracts, Year Four	47
Future Amortization Expenses, Out-of-Market Contracts, Year Five	47
Out of Market Contracts [Member] | Gas Transportation Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Future Amortization Expenses, Out-of-Market Contracts, Year One	37
Future Amortization Expenses, Out-of-Market Contracts, Year Two	32
Future Amortization Expenses, Out-of-Market Contracts, Year Three	29
Future Amortization Expenses, Out-of-Market Contracts, Year Four	29
Future Amortization Expenses, Out-of-Market Contracts, Year Five	$ 26

Debt and Capital Leases (Debt S

Debt and Capital Leases (Debt Schedule)(Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015	Sep. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Mar. 31, 2014
Debt Instrument
Long-term Debt		$ 19,406		$ 19,620
Capital Lease Obligations		8		16
Subtotal		19,414		19,636
Current portion of long-term debt and capital leases		1,220		481
Deferred Finance Costs, Net	[1]	188		172
Long-term debt and capital leases		$ 18,006		18,983
Debt Instrument, Description of Variable Rate Basis		3 month LIBOR
Total premium		$ 82		140
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months		1,222
Long-term Debt, Maturities, Repayments of Principal in Year Two		1,650
Long-term Debt, Maturities, Repayments of Principal in Year Three		839
Long-term Debt, Maturities, Repayments of Principal in Year Four		1,273
Long-term Debt, Maturities, Repayments of Principal in Year Five		1,157
Long-term Debt, Maturities, Repayments of Principal after Year Five		13,192
Long-term Debt, excluding Unamortized Discount (Premium), net		19,333
Recourse Debt
Debt Instrument
Long-term Debt		7,786		8,584
Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		11,620		11,036
Senior notes, due 2018 | Recourse Debt
Debt Instrument
Long-term Debt		$ 398		1,039
Debt Instrument, Interest Rate, Stated Percentage	[2]	7.625%
Senior notes, due 2020 | Recourse Debt
Debt Instrument
Long-term Debt		$ 0		1,058
Debt Instrument, Interest Rate, Stated Percentage		8.25%	[2]		8.25%
Senior notes, due 2021 | Recourse Debt
Debt Instrument
Long-term Debt		$ 207		1,128
Debt Instrument, Interest Rate, Stated Percentage		7.875%	[2]		7.875%
Senior Notes Due In 2022 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 992		1,100
Debt Instrument, Interest Rate, Stated Percentage	[2]	6.25%
Senior notes, due 2023 | Recourse Debt
Debt Instrument
Long-term Debt		$ 869		936
Debt Instrument, Interest Rate, Stated Percentage	[2]	6.625%
Senior Notes 2024 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 733		904
Debt Instrument, Interest Rate, Stated Percentage	[2]	6.25%
Senior Notes due 2026 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 1,000		0
Debt Instrument, Interest Rate, Stated Percentage		7.25%	[2]			7.25%
Senior Notes due 2027 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 1,250		0
Debt Instrument, Interest Rate, Stated Percentage		6.625%	[2]		6.625%
Senior Credit Facility Due 2018 [Member]
Debt Instrument
Unamortized discount on debt instruments	[3]	$ 0		(3)
Senior Credit Facility Due 2018 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 0		1,964
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	2.00%
Term Loan Facility Due 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		1 - month LIBOR
Unamortized discount on debt instruments	[3]	$ (9)		0
Debt Instrument, Unamortized Discount, Current	[1]	1
Term Loan Facility Due 2023 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 1,882		0
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	2.75%
Indian River Power LLC Tax Exempt Bonds Due 2040 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 57		57
Debt Instrument, Interest Rate, Stated Percentage	[2]	0.00%
Indian River Power LLC Tax Exempt Bonds Due 2045 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 190		190
Debt Instrument, Interest Rate, Stated Percentage	[2]	0.00%
Dunkirk Power LLC Tax Exempt Bonds Due 2042 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 59		59
Debt Instrument, Interest Rate, Stated Percentage	[2]	0.00%
Fort Bend County, tax exempt bonds, due 2045 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 22		22
Debt Instrument, Interest Rate, Stated Percentage	[2]	0.00%
Fort Bend County, tax exempt bonds, due 2038 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 54		54
Debt Instrument, Interest Rate, Stated Percentage	[2]	0.00%
Fort Bend County, tax exempt bonds, due 2042 [Member] | Recourse Debt
Debt Instrument
Long-term Debt		$ 73		73
Debt Instrument, Interest Rate, Stated Percentage	[2]	0.00%
Tax-exempt Bonds | Recourse Debt
Debt Instrument
Long-term Debt		$ 455		455
GenOn Senior Notes [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		1,911		1,956
GenOn Senior Notes Due in 2017 [Member]
Debt Instrument
Unamortized premium on debt instruments	[4]	8		23
GenOn Senior Notes Due in 2017 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 699		714
Debt Instrument, Interest Rate, Stated Percentage	[2]	7.875%
GenOn senior notes, due 2018
Debt Instrument
Unamortized premium on debt instruments	[4]	$ 38		59
GenOn senior notes, due 2018 | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 687		708
Debt Instrument, Interest Rate, Stated Percentage	[2]	9.50%
GenOn senior notes, due 2020
Debt Instrument
Unamortized premium on debt instruments	[4]	$ 35		44
GenOn senior notes, due 2020 | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 525		534
Debt Instrument, Interest Rate, Stated Percentage	[2]	9.875%
GenOn Americas Generation senior notes | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 745		752
GenOn Americas Generation Senior Notes Due in 2021 [Member]
Debt Instrument
Unamortized premium on debt instruments	[4]	26		32
GenOn Americas Generation Senior Notes Due in 2021 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 392		398
Debt Instrument, Interest Rate, Stated Percentage	[2]	8.50%
GenOn Americas Generation senior notes, due 2031
Debt Instrument
Unamortized premium on debt instruments	[4]	$ 24		25
GenOn Americas Generation senior notes, due 2031 | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 353		354
Debt Instrument, Interest Rate, Stated Percentage	[2]	9.125%
GenOn Other [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 96		56
Genon [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		2,752		2,764
5.375% Senior Notes due in 2024 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 500		500
Debt Instrument, Interest Rate, Stated Percentage	[2]	5.375%
5.00% Senior Notes due in 2026 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 350		0
Debt Instrument, Interest Rate, Stated Percentage		5.00%	[2]		5.00%
NRG Yield Revolving Credit Facility [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 0		306
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	2.75%
3.5% Convertible Notes due 2019 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage								3.50%
Unamortized discount on debt instruments		$ (10)		(15)
3.5% Convertible Notes due 2019 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 335		330
Debt Instrument, Interest Rate, Stated Percentage	[2]	3.50%
3.25% Convertible Notes due 2020 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage							3.25%
Unamortized discount on debt instruments		$ (17)		(21)
3.25% Convertible Notes due 2020 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 271		266
Debt Instrument, Interest Rate, Stated Percentage	[2]	3.25%
El Segundo Energy Center, due 2023 | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 443		485
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Marsh Landing, due 2017 and 2023
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		1 - month LIBOR
Marsh Landing, due 2017 and 2023 | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 370		418
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Alta Wind I - V Lease financing arrangement [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 965		1,002
Walnut Creek Energy, LLC, due in 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		1 - month LIBOR
Walnut Creek Energy, LLC, due in 2023 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 310		351
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	1.625%
Tapestry Wind LLC due in 2021 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 172		181
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	1.625%
CVSR due 2037 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 771		793
CVSR Holdco due 2037 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 199		0
Debt Instrument, Interest Rate, Stated Percentage	[2]	4.68%
Alpine Financing Agreement, due 2022 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		1 - month LIBOR
Alpine Financing Agreement, due 2022 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 145		154
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	1.75%
NRG Energy Center Minneapolis LLC Senior Secured Notes [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 96		108
NRG Energy Center Minneapolis LLC Senior Secured Notes due 2031 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 125		0
Debt Instrument, Interest Rate, Stated Percentage	[2]	3.55%
Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		6 - month LIBOR
Viento Funding II, Inc., due in 2023 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 178		189
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	2.75%
NRG Yield - Other [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 540		573
NRG Yield, Inc. [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		5,770		5,656
Ivanpah, due 2033 and 2038 | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		1,113		1,149
Agua Caliente, due 2037 | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		849		879
NRG Solar Dandan [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 76		$ 98
Debt Instrument, Description of Variable Rate Basis				LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	2.25%
Peaker bonds, due 2019
Debt Instrument
Unamortized discount on debt instruments	[1]	$ 0		$ (4)
Peaker bonds, due 2019 | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 0		72
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	1.07%
Cedro Hill Wind LLC, due in 2025 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 163		103
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	1.75%
Utah Portfolio [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 287		0
Debt Instrument, Description of Variable Rate Basis	[2]	LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]	2.65%
Midwest Generation due 2019 [Member]
Debt Instrument
Unamortized discount on debt instruments		$ (13)		0
Midwest Generation due 2019 [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 218		0	$ 218
Debt Instrument, Interest Rate, Stated Percentage	[2]	4.39%
NRG Other | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 392		315
NRG Energy [Member] | Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 3,098		$ 2,616
Minimum [Member] | El Segundo Energy Center, due 2023 | Non Recourse Debt [Member]
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]	1.625%
Minimum [Member] | Marsh Landing, due 2017 and 2023 | Non Recourse Debt [Member]
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]	1.75%
Minimum [Member] | Alta Wind I - V Lease financing arrangement [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	5.696%
Minimum [Member] | CVSR due 2037 [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	2.339%
Minimum [Member] | NRG Energy Center Minneapolis LLC Senior Secured Notes [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	5.95%
Minimum [Member] | Ivanpah, due 2033 and 2038 | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	2.285%
Minimum [Member] | Agua Caliente, due 2037 | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	2.395%
Maximum [Member] | El Segundo Energy Center, due 2023 | Non Recourse Debt [Member]
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]	2.25%
Maximum [Member] | Marsh Landing, due 2017 and 2023 | Non Recourse Debt [Member]
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]	1.875%
Maximum [Member] | Alta Wind I - V Lease financing arrangement [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	7.015%
Maximum [Member] | CVSR due 2037 [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	3.775%
Maximum [Member] | NRG Energy Center Minneapolis LLC Senior Secured Notes [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	7.25%
Maximum [Member] | Ivanpah, due 2033 and 2038 | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	4.256%
Maximum [Member] | Agua Caliente, due 2037 | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]	3.633%
[1]	Repaid in 2016.
[2]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.
[3]	Term loan facility, due 2018 replaced with the Term loan facility due 2023. Discount of $1 million was related to current maturities in 2016.
[4]	Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition.

Debt and Capital Leases (NRG Re

Debt and Capital Leases (NRG Recourse Debt 1 Issuances/Repurchases - Details 2) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Debt Instrument
Loss on debt extinguishment				$ 142		$ (75)		$ 95
Senior notes, due 2020
Debt Instrument
Debt Instrument Repurchase, Accrued Interest				77		5
Loss on debt extinguishment				(117)		(19)
Deferred Financing Costs				$ 16		2
Recourse Debt | Senior Notes due 2026 [Member]
Debt Instrument
Proceeds from Issuance of Senior Long-term Debt			$ 1,000
Debt instrument, interest rate, stated percentage (as a percent)			7.25%	7.25%	[1]
Recourse Debt | Senior Notes due 2027 [Member]
Debt Instrument
Proceeds from Issuance of Senior Long-term Debt		$ 1,250
Debt instrument, interest rate, stated percentage (as a percent)		6.625%		6.625%	[1]
Recourse Debt | Senior notes, due 2020
Debt Instrument
Debt instrument, interest rate, stated percentage (as a percent)		8.25%		8.25%	[1]
Debt Instrument, Principal Amount Repurchased				$ 1,058		5
Debt Instrument, Repurchase Amount				$ 1,129	[2]	$ 5	[3]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				(103.12%)		(96.50%)
Recourse Debt | Senior Notes 2024 [Member]
Debt Instrument
Debt instrument, interest rate, stated percentage (as a percent)	[1]			6.25%
Debt Instrument, Principal Amount Repurchased				$ 171		$ 95
Debt Instrument, Repurchase Amount				$ 163	[2]	$ 82	[3]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				(94.52%)		(84.73%)
Recourse Debt | Senior notes, due 2022
Debt Instrument
Debt instrument, interest rate, stated percentage (as a percent)	[1]			6.25%
Debt Instrument, Principal Amount Repurchased				$ 108
Debt Instrument, Repurchase Amount	[2]			$ 105
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				(94.73%)
Recourse Debt | Senior notes, due 2020
Debt Instrument
Debt Instrument, Principal Amount Repurchased				$ 2,967		$ 246
Debt Instrument, Repurchase Amount				$ 3,145	[2]	231	[3]
Recourse Debt | Senior notes, due 2018
Debt Instrument
Debt instrument, interest rate, stated percentage (as a percent)	[1]			7.625%
Debt Instrument, Principal Amount Repurchased				$ 641	[4]	92
Debt Instrument, Repurchase Amount				$ 706	[2],[4]	$ 97	[3]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				(107.89%)	[4]	(102.23%)
Redemptions by Cash				$ 186
Recourse Debt | Senior notes, due 2023
Debt Instrument
Debt instrument, interest rate, stated percentage (as a percent)	[1]			6.625%
Debt Instrument, Principal Amount Repurchased				$ 67		$ 54
Debt Instrument, Repurchase Amount				$ 64	[2]	$ 47	[3]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				(94.13%)		(85.97%)
Recourse Debt | Senior Notes Due In 2021 [Member]
Debt Instrument
Debt instrument, interest rate, stated percentage (as a percent)		7.875%		7.875%	[1]
Debt Instrument, Principal Amount Repurchased	[5]			$ 922
Debt Instrument, Repurchase Amount	[2],[5]			$ 978
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	[5]			(104.00%)
Redemptions by Cash				$ 193
[1]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.
[2]	Includes payment for accrued interest.
[3]	Includes payment for accrued interest.
[4]	$186 million of the redemptions financed by cash on hand.
[5]	$193 million of the redemptions financed by cash on hand.

Debt and Capital Leases Debt an

Debt and Capital Leases Debt and Capital Leases (NRG Recourse Debt 2 - Senior Notes OS) (Details 3)		12 Months Ended
		Dec. 31, 2016		Sep. 30, 2016	Jun. 30, 2016
Recourse Debt [Member]
Debt Instrument
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.
Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]	6.25%
Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]	6.25%
Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		7.875%	[1]	7.875%
Recourse Debt [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]	6.625%
Recourse Debt [Member] | Senior notes, due 2018
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]	7.625%
Recourse Debt [Member] | Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		7.25%	[1]		7.25%
Recourse Debt [Member] | Senior Notes due 2027 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		6.625%	[1]	6.625%
Redemption Period From 15 July 2018 to 14 July 2019 [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.125%
Redemption Period From 1 May 2019 to 30 April 2020 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.125%
Redemption Period From 15 July 2018 to 14 July 2019 [Member] | Recourse Debt [Member] | Senior Notes due 2027 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.313%
Redemption Period From 1 May 2019 to 30 April 2020 [Member] | Recourse Debt [Member] | Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.625%
Redemption Period From 15 September 2017 to 14 September 2018 [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.313%
Redemption Period From 15 May 2016 To 14 May 2017 [Member] | Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.938%
Redemption Period From 15 May 2017 To 14 May 2018 [Member] | Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.625%
Redemption Period From 15 May 2018 To 14 May 2019 [Member] | Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.313%
Redemption Period From 15 May 2019 And Thereafter [Member] | Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period Beginning With 15 September 2020 [Member] | Recourse Debt [Member] | Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period Prior To 15 July 2017 [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to July 15, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings.
Redemption Period Prior To 15 July 2018 [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to July 15, 2018, NRG may redeem all or a part of the 2022 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. 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 103.125% of the note, plus interest payments due on the note from the date of redemption through July 15, 2018, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%.
Redemption Period Prior To 1 May 2017 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to May 1, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2024 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings.
Redemption Period Prior To 1 May 2019 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to May 1, 2019, NRG may redeem all or a part of the 2024 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. 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 103.125% of the note, plus interest payments due on the note from the date of redemption through May 1, 2019 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%.
Redemption Period From 15 September 1018 to 14 September 2019 [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.208%
Redemption Period From 15 September 2019 to 14 September 2020 [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.104%
Redemption Period Beginning With 15 September 2020 [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period From 15 July 2019 to 14 July 2020 [Member] | Recourse Debt [Member] | Senior Notes due 2027 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.208%
Redemption Period From 15 July 2020 And Thereafter [Member] | Recourse Debt [Member] | Senior Notes due 2027 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.104%
Redemption Period Prior to September 15, 2017 [Member] | Recourse Debt [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		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%.
Redemption Period From 1 May 2020 to 30 April 2021 [Member] | Recourse Debt [Member] | Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.417%
Redemption Period From 1 May 2021 to 30 April 2022 [Member] | Recourse Debt [Member] | Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.208%
Redemption Period Prior To 15 May 2019 [Member] | Recourse Debt [Member] | Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to May 15, 2019, NRG may redeem up to 35% of the aggregate principal amount of the 2026 Senior Notes, at a redemption price equal to 107.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings
Redemption Period Prior To 15 May 2021 [Member] | Recourse Debt [Member] | Senior Notes due 2026 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to May 15, 2021, NRG may redeem all or a part of the 2026 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. 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 103.625% of the note, plus interest payments due on the note from the date of redemption through May 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%.
Redemption Period Prior To 15 July 2019 [Member] | Recourse Debt [Member] | Senior Notes due 2027 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to July 15, 2019, NRG may redeem up to 35% of the aggregate principal amount of the 2027 Senior Notes, at a redemption price equal to 106.625% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings.
Redemption Period From 15 July 2024 And Thereafter [Member] | Recourse Debt [Member] | Senior Notes due 2027 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period Prior To 15 July 2021 [Member] | Recourse Debt [Member] | Senior Notes due 2027 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to July 15, 2021 NRG may redeem all or a part of the 2027 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. 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 July 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%.
Redemption Period From 1 May 2020 to 30 April 2021 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.083%
Redemption Period From 1 May 2021 to 30 April 2022 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.042%
Redemption Period From 1 May 2022 And Thereafter [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period From 15 July 2019 to 14 July 2020 [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.563%
Redemption Period From 15 July 2020 And Thereafter [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
[1]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

Debt and Capital Leases Debt 95

Debt and Capital Leases Debt and Capital Leases (NRG Recourse Debt 3 - Sr Cr Facility- TaxExempt Bonds) (Details 4) $ in Millions		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Debt Instrument
Long-term Debt				$ 19,406	$ 19,620
Debt Instrument, Description of Variable Rate Basis				3 month LIBOR
Gain (Loss) on Extinguishment of Debt				$ (142)	75	$ (95)
Term Loan Facility Due 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis				1 - month LIBOR
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis			LIBOR
Line of Credit Facility, Maximum Borrowing Capacity			$ 0
Recourse Debt [Member]
Debt Instrument
Long-term Debt				$ 7,786	8,584
Recourse Debt [Member] | Term Loan Facility Due 2023 [Member]
Debt Instrument
Long-term Debt				$ 1,882	0
Proceeds from Issuance of Senior Long-term Debt			$ 1,900
Debt Instrument, Description of Variable Rate Basis	[1]			LIBOR
Debt Instrument, Basis Spread on Variable Rate	[1]			2.75%
Percent of face value			99.50%
Debt Instrument, Periodic Payment, Percentage of Principal			0.0025
Gain (Loss) on Extinguishment of Debt			$ 21
Recourse Debt [Member] | Term Loan Facility Due 2023 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis			LIBOR
Debt Instrument, Basis Spread on Variable Rate			2.75%
Recourse Debt [Member] | Term Loan Facility Due 2023 [Member] | London Interbank Offered Rate (LIBOR) floor [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis			LIBOR
Debt Instrument, Basis Spread on Variable Rate			0.75%
Recourse Debt [Member] | Indian River Power LLC Tax Exempt Bonds Due 2040 [Member]
Debt Instrument
Long-term Debt				$ 57	57
Debt Instrument, Interest Rate, Stated Percentage	[1]			0.00%
Recourse Debt [Member] | Indian River Power LLC Tax Exempt Bonds Due 2045 [Member]
Debt Instrument
Long-term Debt				$ 190	190
Debt Instrument, Interest Rate, Stated Percentage	[1]			0.00%
Recourse Debt [Member] | Dunkirk Power LLC Tax Exempt Bonds Due 2042 [Member]
Debt Instrument
Long-term Debt				$ 59	59
Debt Instrument, Interest Rate, Stated Percentage	[1]			0.00%
Recourse Debt [Member] | Fort Bend County, tax exempt bonds, due 2045 [Member]
Debt Instrument
Long-term Debt				$ 22	22
Debt Instrument, Interest Rate, Stated Percentage	[1]			0.00%
Recourse Debt [Member] | Fort Bend County, tax exempt bonds, due 2038 [Member]
Debt Instrument
Long-term Debt				$ 54	54
Debt Instrument, Interest Rate, Stated Percentage	[1]			0.00%
Recourse Debt [Member] | Fort Bend County, tax exempt bonds, due 2042 [Member]
Debt Instrument
Long-term Debt				$ 73	73
Debt Instrument, Interest Rate, Stated Percentage	[1]			0.00%
Recourse Debt [Member] | Tax-exempt Bonds
Debt Instrument
Long-term Debt				$ 455	$ 455
Subsequent Event [Member] | Recourse Debt [Member] | Term Loan Facility Due 2023 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.25%
Subsequent Event [Member] | Recourse Debt [Member] | Term Loan Facility Due 2023 [Member] | London Interbank Offered Rate (LIBOR) floor [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		LIBOR
Debt Instrument, Basis Spread on Variable Rate		0.75%
2016 Tranche A Revolving Credit Facility due 2018 [Member] | Revolving Credit Facility [Member]
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity			$ 289
2016 Tranche B Revolving Credit Facility due 2021 [Member] [Member] | Revolving Credit Facility [Member]
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity			$ 2,200
[1]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

Debt and Capital Leases (NRG No

Debt and Capital Leases (NRG Non-Recourse Debt 1 - GenOn Sr Notes) (Details 5) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument
Amount of Restricted Net Assets for Consolidated and Unconsolidated Subsidiaries		$ 4,900
Long-term Debt		19,406	$ 19,620
Gain (Loss) on Extinguishment of Debt		$ (142)	75	$ (95)
GenOn Senior Notes [Member]
Debt Instrument
Debt Instrument, Principal Amount Repurchased			(119)
Debt Instrument, Repurchase Amount			108
Redemption Period Prior To 15 January 2018 [Member] | GenOn senior notes, due 2018
Debt Instrument
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.
Redemption Period From October 15, 2016 to October 14, 2017 [Member] | GenOn senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.292%
Redemption Period From October 15, 2017 to October 14, 2018 [Member] | GenOn senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.646%
Redemption Period Beginning with October 15, 2018 [Member] | GenOn senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period Prior to Maturity [Member] | GenOn Senior Notes Due in 2017 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		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
GenOn Energy [Member]
Debt Instrument
Restricted Payments Limit		$ 250
Other Restricted Assets		368
Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		11,620	11,036
Non Recourse Debt [Member] | GenOn Senior Notes [Member]
Debt Instrument
Long-term Debt		1,911	1,956
Debt Instrument, Principal Amount Repurchased			(119)
Gain (Loss) on Extinguishment of Debt			23
Non Recourse Debt [Member] | GenOn senior notes, due 2018
Debt Instrument
Long-term Debt		$ 687	708
Debt Instrument, Interest Rate, Stated Percentage	[1]	9.50%
Debt Instrument, Principal Amount Repurchased			$ (25)
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed			90.95%
Gain (Loss) on Extinguishment of Debt			$ 5
Non Recourse Debt [Member] | GenOn senior notes, due 2020
Debt Instrument
Long-term Debt		$ 525	534
Debt Instrument, Interest Rate, Stated Percentage	[1]	9.875%
Debt Instrument, Principal Amount Repurchased			$ (61)
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed			83.847%
Gain (Loss) on Extinguishment of Debt			$ 15
Non Recourse Debt [Member] | GenOn Senior Notes Due in 2017 [Member]
Debt Instrument
Long-term Debt		$ 699	714
Debt Instrument, Interest Rate, Stated Percentage	[1]	7.875%
Debt Instrument, Principal Amount Repurchased			$ (33)
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed			95.172%
Gain (Loss) on Extinguishment of Debt			$ 3
[1]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

Debt and Capital Leases Debt 97

Debt and Capital Leases Debt and Capital Leases (NRG Non-Recourse Debt 2 - GAG Sr Notes) (Details 6) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument
Long-term Debt		$ 19,406	$ 19,620
Gain (Loss) on Extinguishment of Debt		$ (142)	75	$ (95)
GenOn Americas Generation Senior Notes Due in 2021 [Member] | Redemption Period Prior to Maturity [Member]
Debt Instrument
Debt Instrument, Redemption, Description		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.
GenOn Americas Generation senior notes
Debt Instrument
Debt Instrument, Principal Amount Repurchased			(155)
Debt Instrument, Repurchase Amount			128
Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		$ 11,620	11,036
Non Recourse Debt [Member] | GenOn Americas Generation Senior Notes Due in 2021 [Member]
Debt Instrument
Long-term Debt		$ 392	398
Debt Instrument, Interest Rate, Stated Percentage	[1]	8.50%
Debt Instrument, Principal Amount Repurchased			$ (84)
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed			84.91%
Gain (Loss) on Extinguishment of Debt			$ 20
Non Recourse Debt [Member] | GenOn Americas Generation senior notes, due 2031
Debt Instrument
Long-term Debt		$ 353	354
Debt Instrument, Interest Rate, Stated Percentage	[1]	9.125%
Debt Instrument, Principal Amount Repurchased			$ (71)
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed			77.018%
Gain (Loss) on Extinguishment of Debt			$ 22
Non Recourse Debt [Member] | GenOn Americas Generation senior notes
Debt Instrument
Long-term Debt		$ 745	752
Debt Instrument, Principal Amount Repurchased			(155)
Gain (Loss) on Extinguishment of Debt			$ 42
[1]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

Debt and Capital Leases Debt 98

Debt and Capital Leases Debt and Capital Leases (NRG Non-Recourse Debt 3 - Yield Notes) (Details 7)		Aug. 05, 2014USD ($)	Dec. 31, 2016USD ($)		Sep. 30, 2016USD ($)	Jun. 30, 2015USD ($)$ / shares	Sep. 30, 2014	Mar. 31, 2014USD ($)$ / shares	Dec. 31, 2015USD ($)
Debt Instrument
Long-term Debt			$ 19,406,000,000						$ 19,620,000,000
NRG Yield Revolving Credit Facility [Member]
Debt Instrument
Line of Credit Facility, Fair Value of Amount Outstanding			0
3.25% Convertible Notes due 2020 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage						3.25%
Convertible Debt						$ 287,500,000
Debt Instrument, Convertible, Conversion Price | $ / shares						$ 27.50
Debt Instrument, Convertible, Conversion Ratio						36.3636
Debt Instrument, Face Amount						$ 1,000
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt						23,000,000
3.5% Convertible Notes due 2019 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage								3.50%
Convertible Debt								$ 345,000,000
Debt Instrument, Convertible, Conversion Price | $ / shares								$ 46.55
Debt Instrument, Convertible, Conversion Ratio								21.4822
Debt Instrument, Face Amount						$ 1,000		$ 1,000
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt								$ 23,000,000
Non Recourse Debt [Member]
Debt Instrument
Long-term Debt			$ 11,620,000,000						11,036,000,000
Non Recourse Debt [Member] | 5.375% Senior Notes due in 2024 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]		5.375%
Long-term Debt			$ 500,000,000						500,000,000
Non Recourse Debt [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument
Long-term Debt			$ 0						306,000,000
Non Recourse Debt [Member] | NRG Energy Center Minneapolis Series D Notes [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage			3.55%
Proceeds from Issuance of Debt			$ 125,000,000
Non Recourse Debt [Member] | 3.25% Convertible Notes due 2020 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]		3.25%
Long-term Debt			$ 271,000,000						266,000,000
Non Recourse Debt [Member] | 3.5% Convertible Notes due 2019 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]		3.50%
Long-term Debt			$ 335,000,000						330,000,000
Non Recourse Debt [Member] | 5.00% Senior Notes due in 2026 [Member]
Debt Instrument
Proceeds from Issuance of Senior Long-term Debt					$ 350,000,000
Debt Instrument, Interest Rate, Stated Percentage			5.00%	[1]	5.00%
Long-term Debt			$ 350,000,000						$ 0
Shelf Facility [Member] | NRG Energy Center Minneapolis Series D Notes [Member]
Debt Instrument
Long-term Debt			70,000,000
Letter of Credit [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument
Letters of Credit Outstanding, Amount			$ 60,000,000
NRG Yield, Inc. [Member] | Non Recourse Debt [Member] | 5.375% Senior Notes due in 2024 [Member]
Debt Instrument
Proceeds from Issuance of Senior Long-term Debt		$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.375%
Adjusted Conversion Ratio [Member] | 3.5% Convertible Notes due 2019 [Member]
Debt Instrument
Debt Instrument, Convertible, Conversion Ratio							42.9644
[1]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

Debt and Capital Leases (NRG 99

Debt and Capital Leases (NRG Non-Recourse Debt 4 - Project Financings) (Details 8) - USD ($) $ in Millions

Jun. 30, 2015

May 29, 2015

Feb. 17, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Jun. 30, 2015

Sep. 30, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Mar. 31, 2016

Jan. 29, 2016

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

3 month LIBOR

Distributions from, net of contributions to, noncontrolling interests in subsidiaries

$ (156)

$ 47

$ 189

Fees Incurred for Termination of Interest Rate Swaps

$ 17

Long-term Debt

$ 19,406

19,406

19,620

Gain (Loss) on Extinguishment of Debt

$ (142)

75

(95)

High Lonesome Mesa, LLC, due in 2017 [Member]

Debt Instrument

Percentage of Ownership

100.00%

West Holdings Credit Agreement due 2023 Tranche A [Member]

Debt Instrument

Proceeds from Issuance of Debt

$ 5

West Holdings Credit Agreement due 2023 Tranche A [Member] | May 29, 2015 to Aug 31, 2017 [Member]

Debt Instrument

Debt Instrument, Basis Spread on Variable Rate

1.625%

West Holdings Credit Agreement Tranche B [Member]

Debt Instrument

Long-term Debt

58

$ 58

West Holdings Credit Agreement due 2023 Tranche B [Member] | May 29, 2015 to Aug 31, 2017 [Member]

Debt Instrument

Debt Instrument, Basis Spread on Variable Rate

2.25%

El Segundo Energy Center, due 2023

Debt Instrument

Gain (Loss) on Extinguishment of Debt

$ (7)

West Holdings Credit Agreement Tranche A [Member]

Debt Instrument

Long-term Debt

385

$ 385

West Holdings PPA [Member]

Debt Instrument

Letters of Credit Outstanding, Amount

33

33

West Holdings Working Capital Facility [Member]

Debt Instrument

Letters of Credit Outstanding, Amount

1

1

Support Debt Service Requirements [Member]

Debt Instrument

Letters of Credit Outstanding, Amount

48

48

Non Recourse Debt [Member]

Debt Instrument

Long-term Debt

11,620

11,620

11,036

Non Recourse Debt [Member] | Agua Caliente Financing Agreement [Member]

Debt Instrument

Long-term Debt

$ 849

$ 849

879

Non Recourse Debt [Member] | NRG Energy Center Minneapolis Series D Notes [Member]

Debt Instrument

Debt Instrument, Interest Rate, Stated Percentage

3.55%

3.55%

Proceeds from Issuance of Debt

$ 125

Non Recourse Debt [Member] | Utah Portfolio [Member]

Debt Instrument

Additional Debt Borrowed

65

$ 65

Debt Instrument, Description of Variable Rate Basis

[1]

LIBOR

Debt Instrument, Basis Spread on Variable Rate

[1]

2.65%

Long-term Debt

287

$ 287

0

Non Recourse Debt [Member] | Utah Portfolio [Member] | London Interbank Offered Rate (LIBOR) [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

2.625%

Non Recourse Debt [Member] | Alta Wind I - V Lease financing arrangement [Member]

Debt Instrument

Long-term Debt

965

$ 965

$ 1,002

Non Recourse Debt [Member] | NRG Solar Dandan [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

[1]

2.25%

Long-term Debt

76

$ 76

$ 98

Non Recourse Debt [Member] | El Segundo Energy Center, due 2023

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

[1]

LIBOR

Long-term Debt

443

$ 443

485

Non Recourse Debt [Member] | Peaker bonds, due 2019

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

[1]

LIBOR

Debt Instrument, Basis Spread on Variable Rate

[1]

1.07%

Long-term Debt

0

$ 0

72

Gain (Loss) on Extinguishment of Debt

$ 3

Debt Instrument, Repurchase Amount including fees

$ 85

Non Recourse Debt [Member] | Midwest Generation due 2019 [Member]

Debt Instrument

Long-term Debt

$ 218

$ 218

$ 218

0

Debt Instrument, Interest Rate, Stated Percentage

[1]

4.39%

4.39%

Non Recourse Debt [Member] | CVSR Financing Agreement [Member]

Debt Instrument

Debt Instrument, Interest Rate, Stated Percentage

4.68%

Proceeds from Issuance of Debt

$ 200

Proceeds from Debt, Net of Issuance Costs

199

Shelf Facility [Member] | NRG Energy Center Minneapolis Series D Notes [Member]

Debt Instrument

Long-term Debt

$ 70

$ 70

Recourse Debt [Member]

Debt Instrument

Long-term Debt

7,786

7,786

8,584

Construction Loans [Member] | NRG Solar Dandan [Member]

Debt Instrument

Long-term Debt

76

76

81

Letters of Credit Outstanding, Amount

$ 5

Term Loan Facility | NRG Solar Dandan [Member]

Debt Instrument

Long-term Debt

$ 79

Letters of Credit, Issued Amount

4

Letters of Credit Outstanding, Amount

4

Cash Grant Loan [Member] | NRG Solar Dandan [Member]

Debt Instrument

Long-term Debt

23

$ 23

$ 23

Working Capital Facility [Member] | El Segundo Energy Center, due 2023

Debt Instrument

Credit Facility, Maximum Borrowing Capacity, Amendment

$ (9)

Alta X and XI TE Holdco [Member]

Debt Instrument

Distributions from, net of contributions to, noncontrolling interests in subsidiaries

$ 119

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind I [Member]

Debt Instrument

Long-term Debt

$ 242

$ 242

Debt Instrument, Interest Rate, Stated Percentage

7.015%

7.015%

Debt Instrument, Maturity Date

Dec. 30, 2034

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind II [Member]

Debt Instrument

Long-term Debt

$ 191

$ 191

Debt Instrument, Interest Rate, Stated Percentage

5.696%

5.696%

Debt Instrument, Maturity Date

Dec. 30, 2034

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind III [Member]

Debt Instrument

Long-term Debt

$ 198

$ 198

Debt Instrument, Interest Rate, Stated Percentage

6.067%

6.067%

Debt Instrument, Maturity Date

Dec. 30, 2034

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind IV [Member]

Debt Instrument

Long-term Debt

$ 128

$ 128

Debt Instrument, Interest Rate, Stated Percentage

5.938%

5.938%

Debt Instrument, Maturity Date

Dec. 30, 2034

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind V [Member]

Debt Instrument

Long-term Debt

$ 206

$ 206

Debt Instrument, Interest Rate, Stated Percentage

6.071%

6.071%

Debt Instrument, Maturity Date

Jun. 30, 2035

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind I - V Lease financing arrangement [Member]

Debt Instrument

Long-term Debt

$ 965

$ 965

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind I [Member]

Debt Instrument

Long-term Debt

$ 16

$ 16

Debt Instrument, Interest Rate, Stated Percentage

3.25%

3.25%

Debt Instrument, Maturity Date

Jan. 5, 2021

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind II [Member]

Debt Instrument

Long-term Debt

$ 27

$ 27

Debt Instrument, Interest Rate, Stated Percentage

2.75%

2.75%

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind III [Member]

Debt Instrument

Long-term Debt

$ 27

$ 27

Debt Instrument, Interest Rate, Stated Percentage

2.75%

2.75%

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind IV [Member]

Debt Instrument

Long-term Debt

$ 19

$ 19

Debt Instrument, Interest Rate, Stated Percentage

2.75%

2.75%

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind V [Member]

Debt Instrument

Long-term Debt

$ 30

$ 30

Debt Instrument, Interest Rate, Stated Percentage

2.75%

2.75%

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind I - V Lease financing arrangement [Member]

Debt Instrument

Long-term Debt

$ 119

$ 119

Midwest Generation [Member] | Non Recourse Debt [Member]

Debt Instrument

Debt Instrument, Interest Rate, Stated Percentage

4.39%

Proceeds from Sale of Other Assets

$ 253

May 29, 2015 to Aug 31, 2017 [Member] | West Holdings Credit Agreement due 2023 Tranche A [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

May 29, 2015 to Aug 31, 2017 [Member] | West Holdings Credit Agreement due 2023 Tranche B [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

September 1, 2017 to August 31, 2020 [Member] | West Holdings Credit Agreement due 2023 Tranche A [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

1.75%

September 1, 2017 to August 31, 2020 [Member] | West Holdings Credit Agreement due 2023 Tranche B [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

2.375%

September 1, 2020 through maturity [Member] | West Holdings Credit Agreement due 2023 Tranche A [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

1.875%

September 1, 2020 through maturity [Member] | West Holdings Credit Agreement due 2023 Tranche B [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

2.50%

Cedro Hill, Broken Bow, & Crofton Bluffs [Member]

Debt Instrument

Credit Facility, Maximum Borrowing Capacity, Amendment

312

Proceeds from Lines of Credit

$ 87

SunEdison Utility-Scale Solar and Wind [Member] | In-development wind assets [Member]

Debt Instrument

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

$ 222

$ 222

Subsequent Event [Member] | Agua Caliente Financing Agreement [Member]

Debt Instrument

Proceeds from Issuance of Senior Long-term Debt

$ 130

Subsequent Event [Member] | Agua Caliente Financing Agreement [Member]

Debt Instrument

Debt Instrument, Interest Rate, Stated Percentage

5.43%

[1]

As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

Debt and Capital Leases (Intere

Debt and Capital Leases (Interest Rate Swaps) (Details 9) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	3 month LIBOR
Interest Rate Swap
Debt Instrument
Derivative, Notional Amount	$ 3,430
GenOn Marsh Landing
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
GenOn Marsh Landing | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	3.244%
Derivative, Notional Amount	$ 342
Iron Springs Renewables [Member]
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	80.00%
Debt Instrument, Description of Variable Rate Basis	1-mo. LIBOR
Iron Springs Renewables [Member] | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	2.555%
Derivative, Notional Amount	$ 34
Four Brothers Holdings [Member]
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	80.00%
Debt Instrument, Description of Variable Rate Basis	1-mo. LIBOR
Four Brothers Holdings [Member] | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	2.567%
Derivative, Notional Amount	$ 141
Granite Mountain Renewables [Member]
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	80.00%
Debt Instrument, Description of Variable Rate Basis	1-mo. LIBOR
Granite Mountain Renewables [Member] | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	2.557%
Derivative, Notional Amount	$ 56
Non Recourse Debt [Member] | El Segundo Energy Center
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Non Recourse Debt [Member] | El Segundo Energy Center | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	2.417%
Derivative, Notional Amount	$ 330
Non Recourse Debt [Member] | NRG Solar Roadrunner LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Non Recourse Debt [Member] | NRG Solar Roadrunner LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	4.313%
Derivative, Notional Amount	$ 28
Non Recourse Debt [Member] | NRG Solar Avra Valley LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Non Recourse Debt [Member] | NRG Solar Avra Valley LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	2.333%
Derivative, Notional Amount	$ 49
Recourse Debt [Member] | NRG Energy [Member]
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Debt Instrument, Description of Variable Rate Basis	1-mo. LIBOR
Recourse Debt [Member] | NRG Energy [Member] | Interest Rate Swap
Debt Instrument
Derivative, Notional Amount	$ 1,000
NRG Other
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
NRG Other | Interest Rate Swap
Debt Instrument
Derivative, Notional Amount	$ 142
Broken Bow Wind [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 58
Cedro Hill Wind LLC, due in 2025 [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	LIBOR	[1]
Cedro Hill Wind LLC, due in 2025 [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	90.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 147
Crofton Bluffs [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 38
Laredo Ridge Wind, LLC, due in 2026 [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	2.31%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 79
Tapestry Wind LLC due in 2021 [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	LIBOR	[1]
Tapestry Wind LLC due in 2021 [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	2.21%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 155
Tapestry Wind LLC due in 2029 [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	50.00%
Derivative, Fixed Interest Rate	3.57%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 60
Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	6 - month LIBOR
Viento Funding II, Inc., due in 2023 [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	LIBOR	[1]
Viento Funding II, Inc., due in 2023 [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	90.00%
Debt Instrument, Description of Variable Rate Basis	6-mo. LIBOR
Derivative, Notional Amount	$ 160
Viento Funding II, Inc., due in 2028 [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	90.00%
Derivative, Fixed Interest Rate	4.985%
Debt Instrument, Description of Variable Rate Basis	6-mo. LIBOR
Derivative, Notional Amount	$ 65
Walnut Creek Energy, LLC, due in 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	1 - month LIBOR
Walnut Creek Energy, LLC, due in 2023 [Member] | Non Recourse Debt [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	LIBOR	[1]
Walnut Creek Energy, LLC, due in 2023 [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 276
WCEP Holdings, LLC, due in 2023 [Member] | Non Recourse Debt [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	90.00%
Derivative, Fixed Interest Rate	4.003%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 46
Alta Wind Asset Management [Member] | Non Recourse Debt [Member] | Alta Wind Holdings [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	100.00%
Derivative, Fixed Interest Rate	2.47%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Derivative, Notional Amount	$ 18
Maturity - June 14, 2028 | Non Recourse Debt [Member] | South Trent Wind LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Maturity - June 14, 2028 | Non Recourse Debt [Member] | South Trent Wind LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	4.95%
Derivative, Notional Amount	$ 21
Maturity - June 14, 2020 | Non Recourse Debt [Member] | South Trent Wind LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Maturity - June 14, 2020 | Non Recourse Debt [Member] | South Trent Wind LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	3.265%
Derivative, Notional Amount	$ 43
Maturity July 15, 2036 [Member] | DGPV 4 [Member]
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Maturity July 15, 2036 [Member] | DGPV 4 [Member] | Interest Rate Swap
Debt Instrument
Derivative, Notional Amount	$ 19
Maturity - December 31, 2029 [Member] | Non Recourse Debt [Member] | NRG Solar Alpine LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Maturity - December 31, 2029 [Member] | Non Recourse Debt [Member] | NRG Solar Alpine LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	2.744%
Derivative, Notional Amount	$ 115
Maturity - June 30, 2025 [Member] | Non Recourse Debt [Member] | NRG Solar Alpine LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Debt Instrument, Description of Variable Rate Basis	3-mo. LIBOR
Maturity - June 30, 2025 [Member] | Non Recourse Debt [Member] | NRG Solar Alpine LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate	2.421%
Derivative, Notional Amount	$ 8
[1]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at the beginning of the period	$ 945
Asset Retirement Obligation, Revision of Estimate	(103)
Additions	49
Spending for current obligations	(8)
Accretion — Expense	42
Accretion — Nuclear decommissioning	15
Balance at the ending of the period	$ 940

Benefit Plans and Other Post102

Benefit Plans and Other Postretirement Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Benefit Plans and Other Postretirement Benefits
Litigation Settlement, Amount			$ 12
Annual periodic pension cost
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	$ 0	$ (21)	0
Pension Benefits
Annual periodic pension cost
Service cost benefits earned	(30)	(32)	(30)
Interest cost on benefit obligation	43	53	53
Expected return on plan assets	(60)	(62)	(62)
Amortization of unrecognized net loss/(gain)	2	2	(6)
Net periodic benefit cost	15	25	15
Pension and other post retirement benefit obligations
Benefit obligation at January 1	1,196	1,305
Service cost	30	32	30
Interest cost	43	53	53
Plan amendments	0	0
Actuarial loss/(gain)	40	(120)
Employee and retiree contributions	0	0
Benefit payments	(68)	(74)
Defined Benefit Plan, Curtailments	0	0
Benefit obligation at December 31	1,241	1,196	1,305
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1	916	988
Actual return on plan assets	72	(26)
Employee and retiree contributions	0	0
Employer contributions	33	28
Benefit payments	(68)	(74)
Fair value of plan assets at December 31	953	916	988
Funded status at December 31 — excess of obligation over assets	(288)	(280)
Other Postretirement Benefits
Annual periodic pension cost
Service cost benefits earned	(2)	(3)	(3)
Interest cost on benefit obligation	6	9	9
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(5)	(5)	(17)
Amortization of unrecognized net loss/(gain)	0	1	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	(14)	0
Net periodic benefit cost	3	(6)	(5)
Pension and other post retirement benefit obligations
Benefit obligation at January 1	178	238
Service cost	2	3	3
Interest cost	6	9	9
Plan amendments	(42)	(6)
Actuarial loss/(gain)	(2)	(31)
Employee and retiree contributions	3	2
Benefit payments	(17)	(12)
Defined Benefit Plan, Curtailments	0	25
Benefit obligation at December 31	128	178	238
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1	0	0
Actual return on plan assets	0	0
Employee and retiree contributions	3	2
Employer contributions	14	10
Benefit payments	(17)	(12)
Fair value of plan assets at December 31	0	0	$ 0
Funded status at December 31 — excess of obligation over assets	(128)	$ (178)
Scenario, Plan [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Expected contribution to the Company's pension plans in 2014	$ 36

Benefit Plans and Other Post103

Benefit Plans and Other Postretirement Benefits (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Amounts recognized in balance sheet
Current liabilities	$ 0	$ 0
Non-current liabilities	288	280
Amounts recognized in accumulated OCI
Net loss/(gain)	94	68
Prior service cost/(credit)	3	3
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial loss/(gain)	28	(31)
Amortization of net actuarial (gain)/loss	(2)	(2)	$ 6
Prior service credit	0	(1)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	0	0
Defined Benefit Plan, Curtailment Recognized in OCI	0	0
Total recognized in other comprehensive loss	(26)	34
Total recognized in net periodic pension cost/(credit) and other comprehensive loss/(income)	41	(8)
Estimated unrecognized loss for NRG's pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year	4
Significant components of NRG's domestic pension plan
Projected benefit obligation	1,241	1,196	1,305
Accumulated benefit obligation	1,174	1,115
Fair value of plan assets	953	916	988
Other Postretirement Benefits
Amounts recognized in balance sheet
Current liabilities	8	12
Non-current liabilities	120	166
Amounts recognized in accumulated OCI
Net loss/(gain)	(11)	(9)
Prior service cost/(credit)	(45)	(9)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial loss/(gain)	(2)	(31)
Amortization of net actuarial (gain)/loss	0	(1)	0
Prior service credit	(41)	(7)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	5	5
Defined Benefit Plan, Curtailment Recognized in OCI	0	(11)
Total recognized in other comprehensive loss	38	45
Total recognized in net periodic pension cost/(credit) and other comprehensive loss/(income)	36	(37)
Defined Benefit Plan, Future Amortization of Gain (Loss)	1
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)	8
Significant components of NRG's domestic pension plan
Projected benefit obligation	128	178	238
Fair value of plan assets	$ 0	$ 0	$ 0

Benefit Plans and Other Post104

Benefit Plans and Other Postretirement Benefits (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Minimum [Member]
Significant assumptions used to calculate NRG's benefit expense
Aon Hewitt above median yield curve discount rate (in years)	6 months
Maximum [Member]
Significant assumptions used to calculate NRG's benefit expense
Aon Hewitt above median yield curve discount rate (in years)	99 years
Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	$ 953	$ 916	$ 988
Significant assumptions used to calculate NRG's benefit obligations
Discount rate	4.26%	4.52%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.00%	3.00%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	4.52%	4.16%	4.99%
Expected return on plan assets	6.65%	6.36%	6.81%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.00%	3.45%	3.65%
Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0	$ 0
Significant assumptions used to calculate NRG's benefit obligations
Discount rate	4.29%	4.55%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	4.55%	4.20%	5.06%
Expected return on plan assets	0.00%	0.00%	0.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	0.00%	0.00%	0.00%
Common/collective trust investment — U.S. equity | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	$ 283	$ 255
Target allocations
Defined Benefit Plan, Target Plan Asset Allocations	27.00%
Common/collective trust investment — non-U.S. equity | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	$ 149	147
Target allocations
Defined Benefit Plan, Target Plan Asset Allocations	15.00%
Common Trust Investment Global Equity [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	$ 104	90
Target allocations
Defined Benefit Plan, Target Plan Asset Allocations	10.00%
Emerging Market Equities [Member] | Pension Benefits
Target allocations
Defined Benefit Plan, Target Plan Asset Allocations	3.00%
Common/collective trust investment — fixed income | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	$ 383	400
Target allocations
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Partnership [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	$ 31	18
Short-term Investments [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	3	6
Fair Value, Inputs, Level 2 [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	950	910
Fair Value, Inputs, Level 2 [Member] | Common/collective trust investment — U.S. equity | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	283	255
Fair Value, Inputs, Level 2 [Member] | Common/collective trust investment — non-U.S. equity | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	149	147
Fair Value, Inputs, Level 2 [Member] | Common Trust Investment Global Equity [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	104	90
Fair Value, Inputs, Level 2 [Member] | Common/collective trust investment — fixed income | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	383	400
Fair Value, Inputs, Level 2 [Member] | Partnership [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	31	18
Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	3	6
Fair Value, Inputs, Level 1 [Member] | Common/collective trust investment — U.S. equity | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Common/collective trust investment — non-U.S. equity | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Common Trust Investment Global Equity [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Common/collective trust investment — fixed income | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Partnership [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Short-term Investments [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Fair Value of Plan Assets	$ 3	$ 6
Net Period Benefit Cost/Credit [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2,025	2,023	2,019
Net Period Benefit Cost/Credit [Member] | Before age 65 [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	7.25%	8.60%	8.50%
Net Period Benefit Cost/Credit [Member] | Age 65 and after [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	5.00%	5.00%	5.50%
Postretirement Benefit Obligation [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2,025	2,025
Postretirement Benefit Obligation [Member] | Before age 65 [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	7.00%	7.25%
Postretirement Benefit Obligation [Member] | Age 65 and after [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	5.00%	5.00%

Benefit Plans and Other Post105

Benefit Plans and Other Postretirement Benefits (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	0
Effect on postretirement benefit obligation, 1-Percentage-Point Increase	9
Effect on postretirement benefit obligation, 1-Percentage-Point Decrease	(8)
Company's contributions to 401(k) plans
Company contributions to defined contribution plans	$ 55	$ 53	$ 47
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	$ 7	9
Expected reimbursement of contribution to retirement plan obligations to STPNOC in 2014	12
Pension Benefits
NRG's expected future benefit payments
Expected future benefit payments, Next Twelve Months	66
Expected future benefit payments, Year Two	69
Expected future benefit payments, Year Three	72
Expected future benefit payments, Year Four	76
Expected future benefit payments, Year Five	79
Expected future benefit payments, Five Fiscal Years Thereafter	417
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(288)	(280)
Net periodic benefit costs	15	25	15
Total recognized in other comprehensive loss	(26)	34
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	(74)	(63)
Net periodic benefit costs	7	10
Total recognized in other comprehensive loss	11	(8)
Other Postretirement Benefits
NRG's expected future benefit payments
Expected future benefit payments, Next Twelve Months	8
Expected future benefit payments, Year Two	8
Expected future benefit payments, Year Three	8
Expected future benefit payments, Year Four	9
Expected future benefit payments, Year Five	9
Expected future benefit payments, Five Fiscal Years Thereafter	38
Medicare prescription drug reimbursements
Expected Medicare prescription drug reimbursements, Next Twelve Months	0
Expected Medicare prescription drug reimbursements, Year Two	0
Expected Medicare prescription drug reimbursements, Year Three	0
Expected Medicare prescription drug reimbursements, Year Four	0
Expected Medicare prescription drug reimbursements, Year Five	0
Expected Medicare prescription drug reimbursements, After Year Five	1
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(128)	(178)
Net periodic benefit costs	3	(6)	$ (5)
Total recognized in other comprehensive loss	38	45
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	(23)	(26)
Net periodic benefit costs	(2)	(8)
Total recognized in other comprehensive loss	$ (1)	$ 6

Capital Structure (Rollforward

Capital Structure (Rollforward - Details 1) - shares	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012
Capital Structure
Preferred stock, shares authorized		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
2.822% convertible perpetual preferred stock, shares issued		0	250,000
2.822% convertible perpetual preferred stock, shares outstanding		0	250,000
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued	417,583,825	416,939,950
Beginning balance, treasury shares	(102,140,814)	(102,749,908)
Beginning balance, common shares outstanding	315,443,011	314,190,042
Ending balance, common shares issued		417,583,825	416,939,950
Ending balance, treasury shares		(102,140,814)	(102,749,908)
Ending balance, common shares outstanding		315,443,011	314,190,042
Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued	417,583,825	416,939,950	415,506,176	401,126,780
Beginning balance, common shares outstanding	315,443,011	314,190,042	336,662,624	323,779,252
Shares issued under ESPP		609,094	283,139	128,336
Shares issued from LTIP		643,875	1,433,774	1,707,419
Stock Repurchased During Period, Shares			24,189,495	1,624,360
Ending balance, common shares issued		417,583,825	416,939,950	415,506,176
Ending balance, common shares outstanding		315,443,011	314,190,042	336,662,624
Treasury Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, treasury shares	102,140,814	102,749,908	78,843,552	77,347,528
Shares issued under ESPP		609,094	283,139	128,336
Shares issued from LTIP		0	0	0
Stock Repurchased During Period, Shares			24,189,495	1,624,360
Ending balance, treasury shares		102,140,814	102,749,908	78,843,552
EME [Member]
Increase (Decrease) in Stockholders' Equity (in shares)
Shares issued in connection with the EME acquisition				12,671,977
EME [Member] | Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Shares issued in connection with the EME acquisition				12,671,977
EME [Member] | Treasury Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Shares issued in connection with the EME acquisition				0
Subsequent Event [Member] | Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Shares issued under ESPP	282,530

Capital Structure (Common Stock

Capital Structure (Common Stock - Details 2) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended													12 Months Ended				13 Months Ended
		Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common Stock, Dividends, Per Share, Cash Paid			$ 0.00030	$ 0.00030	$ 0.00030	$ 0.00145	$ 0.00145	$ 0.00145	$ 0.00145	$ 0.00145	$ 0.00140	$ 0.00140	$ 0.00140	$ 0.00120				$ 0.14
Common Stock, Dividends, Proposed Annual Percentage Increase			79.00%				4.00%									79.00%	4.00%		4.00%
Dividends Per Common Share																$ 0.24	$ 0.58	$ 0.54
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)			667,819													667,819
Commissions per Share																			$ 0.015
Common Stock
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common stock issued to employee from treasury stock (in shares)																609,094	283,139	128,336
Stock Repurchased During Period, Shares																	(24,189,495)	(1,624,360)
Scenario, Plan [Member]
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common Stock, Dividends, Proposed Annual Amount, Per Share																$ 0.12	$ 0.0058	$ 0.56
Subsequent Event [Member]
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Dividends Payable, Date Declared		Jan. 18, 2017
Dividends Per Common Share		$ 0.0003
Dividends Payable, Date to be Paid		Feb. 15, 2017
Dividends Payable, Date of Record		Feb. 1, 2017
Subsequent Event [Member] | Common Stock
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common stock issued to employee from treasury stock (in shares)		282,530
Subsequent Event [Member] | Scenario, Plan [Member]
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common Stock, Dividends, Proposed Annual Amount, Per Share															$ 0.0012
Long-term incentive plans
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common Stock, Capital Shares Reserved for Future Issuance			17,336,092													17,336,092
Capital Allocation Plan [Member]
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Stock Repurchase Program, Authorized Amount								$ 481
Stock Repurchased During Period, Shares							5,558,920	11,104,184	4,379,907	3,146,484	1,624,360								25,813,855
Treasury Stock Acquired, Average Cost Per Share	[1]						$ 15.03	$ 15.06	$ 24.53	$ 25.15	$ 26.95
Stock Repurchased During Period, Value							$ 84	$ 167	$ 107	$ 79	$ 44								$ 481
[1]	The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.015 per share paid in connection with the share repurchase.

Capital Structure (Preferred St

Capital Structure (Preferred Stock - Details 3)	3 Months Ended	12 Months Ended
	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 13, 2016USD ($)	May 24, 2016USD ($)	Dec. 23, 2014USD ($)	Dec. 31, 2013USD ($)	Aug. 11, 2005shares
Capital Structure
Preferred Stock Instrument, Interest Rate, Stated Percentage		282.20%	282.20%				362.50%
Loss on Extinguishment of Preferred Stock				$ 42,000,000
Redeemable Preferred Stock, Fair Value							$ 291,000,000
Consent Fees Paid, Preferred Stock		$ 0	$ 0	5,000,000
Temporary Equity, Redemption Percentage					1	1
Temporary Equity, Liquidation Preference						$ 344,500,000
Payments for Repurchase of Redeemable Preferred Stock	$ (226,000,000)	(226,000,000)	0	0
Gain on Redemption of Redeemable Preferred Stock	$ 78,000,000	(78,000,000)	0	0
2.822% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding at December 31, 2015		0	302,000,000	$ 291,000,000	$ 304,000,000			$ 249,000,000
Preferred Stock, Accretion of Redemption Discount		$ 2,000,000	$ 11,000,000
Convertible Preferred Stock [Member]
Capital Structure
Preferred Stock, Shares Issued | shares									250,000
Preferred Stock, Dividend Rate, Percentage				3.625%
Preferred Stock, Dividend Rate Amended, Percentage		2.822%	2.822%	2.822%

Investments Accounted for by109

Investments Accounted for by the Equity Method and Variable Interest Entities (Details) $ in Millions		Dec. 31, 2016USD ($)MW	Sep. 30, 2016	Dec. 31, 2015USD ($)	Sep. 30, 2014MW	Dec. 31, 2009MW
Investments Accounted for by the Equity Method
Equity investments in affiliates		$ 1,120		$ 1,045
Undistributed earnings by equity investment		$ 101		$ 55
GenConn Energy LLC (a)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		50.00%
Equity investments in affiliates		$ 106
Petra Nova Parish Holdings [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)			50.00%
Power Generation Capacity, Megawatts | MW					75
Sherbino I Wind Farm LLC
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)						50.00%
Power Generation Capacity, Megawatts | MW						150
Gladstone Power Station (b)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		37.50%
Equity investments in affiliates		$ 132
Power Generation Capacity, Megawatts | MW		1,613
United States | Avenal Solar Holdings LLC (a)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[1]	50.00%
Equity investments in affiliates	[1]	$ (7)
United States | Community Wind North, LLC [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		99.00%
Equity investments in affiliates		$ 21
United States | Desert Sunlight [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[1]	25.00%
Equity investments in affiliates	[1]	$ 282
United States | Elkhorn Ridge Wind, LLC [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[1]	47.00%
Equity investments in affiliates	[1]	$ 85
United States | GenConn Energy LLC (a)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[1]	50.00%
Equity investments in affiliates	[1]	$ 106
United States | Four Brothers Holdings [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		50.00%
Equity investments in affiliates		$ 208
United States | Granite Mountain Renewables [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		50.00%
Equity investments in affiliates		$ 90
United States | Iron Springs Renewables [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		50.00%
Equity investments in affiliates		$ 48
United States | Midway-Sunset Cogeneration Company [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		50.00%
Equity investments in affiliates		$ 22
United States | Petra Nova Parish Holdings [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		50.00%
Equity investments in affiliates		$ 34
United States | Saguaro Power Company
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		50.00%
Equity investments in affiliates		$ (14)
United States | San Juan Mesa Wind Project, LLC [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[1]	75.00%
Equity investments in affiliates	[1]	$ 74
United States | Sherbino I Wind Farm LLC
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		50.00%
Equity investments in affiliates		$ 0
United States | Watson Cogeneration Company [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)		49.00%
Equity investments in affiliates		$ 26
United States | Various [Member]
Investments Accounted for by the Equity Method
Equity investments in affiliates		$ 13
Australia | Gladstone Power Station (b)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[2]	37.50%
Equity investments in affiliates	[2]	$ 132
Mechanically-complete solar assets [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Investments Accounted for by the Equity Method
Power Generation Capacity, Megawatts | MW		530
In-development solar assets [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Investments Accounted for by the Equity Method
Power Generation Capacity, Megawatts | MW		71
NRG [Member] | Mechanically-complete solar assets [Member] | SunEdison Utility-Scale Solar and Wind [Member]
Investments Accounted for by the Equity Method
Power Generation Capacity, Megawatts | MW		265
[1]	Equity method investments owned by NRG Yield
[2]	Gladstone Power Station is located in Australia

Investments Accounted for by110

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities (VIEs - Details 2) $ in Millions	1 Months Ended		12 Months Ended
	Apr. 30, 2009	Dec. 31, 2008	Dec. 31, 2016USD ($)MWfacility	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 17, 2013USD ($)	Dec. 31, 2009MW
Schedule of Equity Method Investments [Line Items]
Long-term Debt			$ 19,406	$ 19,620
Working Capital Facility, Amount Drawn			14
Equity investments in affiliates			1,120	1,045
Other than Temporary Impairment Losses, Investments			$ 268	56	$ 0
GenConn Energy LLC (a)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Number of Peaking Facilities to be Constructed | facility			2
Power Generation Capacity of Peaking Facility to be Constructed | MW			190
Equity investments in affiliates			$ 106
Sherbino I Wind Farm LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
Power Generation Capacity, Megawatts | MW							150
Other than Temporary Impairment Losses, Investments			70
GenConn Working Capital Facility [Member] | GenConn Energy LLC (a)
Schedule of Equity Method Investments [Line Items]
Length of Revolving Working Capital, Loan and Letter of Credit Facility	5 years
Non Recourse Debt [Member]
Schedule of Equity Method Investments [Line Items]
Long-term Debt			11,620	$ 11,036
Non Recourse Debt [Member] | GenConn Facility [Member] | GenConn Energy LLC (a)
Schedule of Equity Method Investments [Line Items]
Long-term Debt			212			$ 237
Debt Instrument, Interest Rate, Stated Percentage						4.73%
Non Recourse Debt [Member] | GenConn Working Capital Facility [Member] | GenConn Energy LLC (a)
Schedule of Equity Method Investments [Line Items]
Long-term Debt						$ 35
Debt Instrument, Interest Rate, Stated Percentage						1.875%
Non Recourse Debt [Member] | Sherbino I Wind Farm LLC Term Loan Facility [Member] | Sherbino I Wind Farm LLC
Schedule of Equity Method Investments [Line Items]
Length of Term Loan Facility		15 years
Long-term Line of Credit			$ 72

Investments Accounted for by111

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities (Other Equity Inv - Details 3) $ in Millions	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)
Schedule of Equity Method Investments [Line Items]
Equity investments in affiliates	$ 1,120	$ 1,045
Deficit Restoration Obligation	88
Equity Method Investment, Summarized Financial Information, Current Assets	87	84
Equity Method Investments, Summarized Financial Data, Property, Plant and Equipment	1,534	1,807
Equity Method Investments, Summarized Financial Information, Other long-term assets	954	863
Equity Method Investment, Summarized Financial Information, Assets	2,575	2,754
Equity Method Investment, Summarized Financial Information, Current Liabilities	59	56
Equity Method Investments, Summarized Financial Information, Long Term Debt	442	366
Equity Method Investments, Summarized Financial Information, Other long-term liabilities	183	179
Equity Method Investment, Summarized Financial Information, Liabilities	684	601
Equity Method Investment, Summarized Financial Information, Noncontrolling Interest	529	493
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net	$ 1,362	$ 1,660
Gladstone Power Station (b)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	37.50%
Power Generation Capacity, Megawatts | MW	1,613
Equity investments in affiliates	$ 132

Segment Reporting (Details)

Segment Reporting (Details) $ in Millions	3 Months Ended										12 Months Ended
	Dec. 31, 2016USD ($)		Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)		Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)customer		Dec. 31, 2015USD ($)customer		Dec. 31, 2014USD ($)customer		Sep. 01, 2016
Income Statement
Operating revenues	$ 2,532		$ 3,952	$ 2,638	$ 3,229	$ 3,011		$ 4,434	$ 3,400	$ 3,829	$ 12,351		$ 14,674		$ 15,868
Cost of revenue including selling marketing and general administrative											9,656		11,983		12,824
Depreciation and amortization											1,367		1,566		1,523
Asset Impairment Charges											918		5,030		97
Acquisition-related transaction and integration costs											8		10		84
Research and Development Expense											90		146		88
Costs and Expenses											12,039		18,735		14,616
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											215		0		19
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments											0		21		0
Operating Income (Loss)	(791)		755	87	476	(4,727)		379	232	76	527		(4,040)		1,271
Equity in (losses)/earnings of unconsolidated affiliates											27		36		38
Other than Temporary Impairment Losses, Investments											(268)		(56)		0
Other Nonoperating Income (Expense)											42		33		22
Gain (Loss) on Extinguishment of Debt											(142)		75		(95)
Gain on Sale of Investments											0		(14)		18
Interest expense											(1,061)		(1,128)		(1,119)
(Loss)/income before income taxes											(875)		(5,094)		135
Income tax expense											16		1,342		3
Net (Loss)/Income	(1,055)		393	(276)	47	(6,358)		67	(9)	(136)	(891)		(6,436)		132
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(68)		(9)	(5)	(35)	(44)		1	5	(16)	(117)		(54)		(2)
Net (loss)/income attributable to NRG Energy, Inc.	(987)		$ 402	$ (271)	$ 82	(6,314)		$ 66	$ (14)	$ (120)	(774)		(6,382)		134
Operating revenues include inter-segment sales and net derivative gains and losses of:											1,117		1,171		2,002
Balance sheet
Equity investments in affiliates	1,120					1,045					1,120		1,045
Capital expenditures	1,242	[1]				1,267	[2]				1,242	[1]	1,267	[2]
Goodwill	662					999					662		999
Total assets	30,355					32,882					30,355		32,882
NRG Yield
Income Statement
Operating revenues											1,021	[3]	953	[4]	828	[5]
Cost of revenue including selling marketing and general administrative											322		333		285
Depreciation and amortization											297		297		233
Asset Impairment Charges											183		0		0
Acquisition-related transaction and integration costs											1		3		4
Research and Development Expense											0		0		0
Costs and Expenses											803		633		522
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											218		320		306
Equity in (losses)/earnings of unconsolidated affiliates											37		26		17
Other than Temporary Impairment Losses, Investments											0		0
Other Nonoperating Income (Expense)											3		3		6
Gain (Loss) on Extinguishment of Debt											0		(9)		(1)
Gain on Sale of Investments													0		0
Interest expense											274		263		(216)
(Loss)/income before income taxes											(16)		77		112
Income tax expense											(1)		12		4
Net (Loss)/Income											(15)		65		108
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(54)		19		16
Net (loss)/income attributable to NRG Energy, Inc.											39		46		92
Operating revenues include inter-segment sales and net derivative gains and losses of:											8		29		12
Balance sheet
Equity investments in affiliates	710					697					710		697
Capital expenditures	23	[1]				30	[2]				23	[1]	30	[2]
Goodwill	0					0					0		0
Total assets	8,383					8,689					8,383		8,689
Corporate
Income Statement
Operating revenues											137	[3]	14	[4]	82	[5]
Cost of revenue including selling marketing and general administrative											235		310		171
Depreciation and amortization											64		59		38
Asset Impairment Charges											33		132		(22)
Acquisition-related transaction and integration costs											7		6		76
Research and Development Expense											24		63		35
Costs and Expenses											363		570		298
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											(78)				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											(304)		(556)		(216)
Equity in (losses)/earnings of unconsolidated affiliates											7		(3)		0
Other than Temporary Impairment Losses, Investments											21		42
Other Nonoperating Income (Expense)											62		77		75
Gain (Loss) on Extinguishment of Debt											(142)		84		(93)
Gain on Sale of Investments													(14)		0
Interest expense											658		779		(806)
(Loss)/income before income taxes											(1,056)		(1,233)		(1,040)
Income tax expense											37		1,347		(5)
Net (Loss)/Income											(1,093)		(2,580)		(1,035)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											16		(37)		5
Net (loss)/income attributable to NRG Energy, Inc.											(1,109)		(2,543)		(1,040)
Operating revenues include inter-segment sales and net derivative gains and losses of:											191		213		85
Balance sheet
Equity investments in affiliates	91					127					91		127
Capital expenditures	51	[1]				246	[2]				51	[1]	246	[2]
Goodwill	111					111					111		111
Total assets	15,734					19,926					15,734		19,926
Eliminations
Income Statement
Operating revenues											(1,117)		(1,171)		(2,002)
Cost of revenue including selling marketing and general administrative											(1,123)		(1,149)		(2,052)
Depreciation and amortization											0		0		0
Asset Impairment Charges											0		22		0
Acquisition-related transaction and integration costs											0		0		0
Research and Development Expense											0		0		0
Costs and Expenses											(1,123)		(1,127)		(2,052)
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											6		(44)		50
Equity in (losses)/earnings of unconsolidated affiliates											18		(6)		2
Other than Temporary Impairment Losses, Investments											0		0
Other Nonoperating Income (Expense)											(61)		(98)		(99)
Gain (Loss) on Extinguishment of Debt											0		0		0
Gain on Sale of Investments													0		0
Interest expense											(59)		(95)		96
(Loss)/income before income taxes											22		(53)		49
Income tax expense											0		0		0
Net (Loss)/Income											22		(53)		49
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(66)		(42)		(24)
Net (loss)/income attributable to NRG Energy, Inc.											88		(11)		73
Operating revenues include inter-segment sales and net derivative gains and losses of:											0		0		0
Balance sheet
Equity investments in affiliates	(257)					(247)					(257)		(247)
Capital expenditures	0	[1]				0	[2]				0	[1]	0	[2]
Goodwill	0					0					0		0
Total assets	(13,865)					(20,075)					(13,865)		(20,075)
Generation [Member]
Income Statement
Operating revenues											6,927	[3]	9,097	[4]	11,113	[5]
Cost of revenue including selling marketing and general administrative											6,020		7,744		8,993
Depreciation and amortization											712		907		966
Asset Impairment Charges											646		4,827		87
Acquisition-related transaction and integration costs											0		0		1
Research and Development Expense											26		31		13
Costs and Expenses											7,404		13,509		10,060
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											293				19
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													21
Operating Income (Loss)											(184)		(4,391)		1,072
Equity in (losses)/earnings of unconsolidated affiliates											(5)		10		23
Other than Temporary Impairment Losses, Investments											142		14
Other Nonoperating Income (Expense)											37		48		39
Gain (Loss) on Extinguishment of Debt											0		0		0
Gain on Sale of Investments													0		18
Interest expense											80		98		(95)
(Loss)/income before income taxes											(374)		(4,445)		1,057
Income tax expense											0		1		4
Net (Loss)/Income											(374)		(4,446)		1,053
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											0		0		(1)
Net (loss)/income attributable to NRG Energy, Inc.											(374)		(4,446)		1,054
Operating revenues include inter-segment sales and net derivative gains and losses of:											893		898		1,873
Balance sheet
Equity investments in affiliates	204					334					204		334
Capital expenditures	779	[1]				798	[2]				779	[1]	798	[2]
Goodwill	199					536					199		536
Total assets	13,234					17,324					13,234		17,324
Retail [Member]
Income Statement
Operating revenues											4,966	[3]	5,389	[4]	5,503	[5]
Cost of revenue including selling marketing and general administrative											3,987		4,561		5,236
Depreciation and amortization											104		123		122
Asset Impairment Charges											0		36		0
Acquisition-related transaction and integration costs											0		1		3
Research and Development Expense											0		0		0
Costs and Expenses											4,091		4,721		5,361
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											875		668		142
Equity in (losses)/earnings of unconsolidated affiliates											0		0		0
Other than Temporary Impairment Losses, Investments											0		0
Other Nonoperating Income (Expense)											0		0		0
Gain (Loss) on Extinguishment of Debt											0		0		0
Gain on Sale of Investments													0		0
Interest expense											0		0		(1)
(Loss)/income before income taxes											875		668		141
Income tax expense											0		0		0
Net (Loss)/Income											875		668		141
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											0		0		0
Net (loss)/income attributable to NRG Energy, Inc.											875		668		141
Operating revenues include inter-segment sales and net derivative gains and losses of:											2		6		7
Balance sheet
Equity investments in affiliates	0					0					0		0
Capital expenditures	59	[1]				30	[2]				59	[1]	30	[2]
Goodwill	340					340					340		340
Total assets	1,589					1,876					1,589		1,876
Renewables [Member]
Income Statement
Operating revenues											417	[3]	392	[4]	344	[5]
Cost of revenue including selling marketing and general administrative											215		184		191
Depreciation and amortization											190		180		164
Asset Impairment Charges											56		13		32
Acquisition-related transaction and integration costs											0		0		0
Research and Development Expense											40		52		40
Costs and Expenses											501		429		427
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											(84)		(37)		(83)
Equity in (losses)/earnings of unconsolidated affiliates											(30)		9		(4)
Other than Temporary Impairment Losses, Investments											105		0
Other Nonoperating Income (Expense)											1		3		1
Gain (Loss) on Extinguishment of Debt											0		0		(1)
Gain on Sale of Investments													0		0
Interest expense											108		83		(97)
(Loss)/income before income taxes											(326)		(108)		(184)
Income tax expense											(20)		(18)		0
Net (Loss)/Income											(306)		(90)		(184)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(13)		6		2
Net (loss)/income attributable to NRG Energy, Inc.											(293)		(96)		(186)
Operating revenues include inter-segment sales and net derivative gains and losses of:											23		25		$ 25
Balance sheet
Equity investments in affiliates	372					134					372		134
Capital expenditures	330	[1]				163	[2]				330	[1]	163	[2]
Goodwill	12					12					12		12
Total assets	5,280					5,142					$ 5,280		$ 5,142
Customers
Segment Reporting Information
Concentration Risk, Number of Customers Accouting for More Than Ten Percent of Revenues | customer											1,000,000		1,000,000		1,000,000
Threshold percentage of the Company's consolidated revenues attributable to a customer											10.00%		10.00%		10.00%
CVSR [Member]
Segment Reporting Information
Percentage of Ownership Sold of Subsidiary																	51.05%
Segment Recast [Member]
Income Statement
Operating revenues											$ 12,351		$ 14,674		$ 15,868
Cost of revenue including selling marketing and general administrative											9,656		11,983		12,824
Depreciation and amortization											1,367		1,566		1,523
Asset Impairment Charges											918		5,030		97
Acquisition-related transaction and integration costs											8		10		84
Research and Development Expense											90		146		88
Costs and Expenses											12,039		18,735		14,616
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											215				19
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													21
Operating Income (Loss)											527		(4,040)		1,271
Equity in (losses)/earnings of unconsolidated affiliates											27		36		38
Other than Temporary Impairment Losses, Investments											(268)		(56)
Other Nonoperating Income (Expense)											42		33		22
Gain (Loss) on Extinguishment of Debt											(142)		75		(95)
Gain on Sale of Investments													(14)		18
Interest expense											(1,061)		(1,128)		1,119
(Loss)/income before income taxes											(875)		(5,094)		135
Income tax expense											16		1,342		3
Net (Loss)/Income											(891)		(6,436)		132
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(117)		(54)		(2)
Net (loss)/income attributable to NRG Energy, Inc.											(774)		(6,382)		134
Operating revenues include inter-segment sales and net derivative gains and losses of:											1,179		1,170		2,002
Balance sheet
Equity investments in affiliates	1,120					1,045					1,120		1,045
Capital expenditures	1,242	[6]				1,267	[7]				1,242	[6]	1,267	[7]
Goodwill	662					999					662		999
Total assets	30,355					32,882					30,355		32,882
Segment Recast [Member] | NRG Yield
Income Statement
Operating revenues											1,021	[8]	953	[9]	828	[10]
Cost of revenue including selling marketing and general administrative											322		333		285
Depreciation and amortization											297		297		233
Asset Impairment Charges											183		0		0
Acquisition-related transaction and integration costs											1		3		4
Research and Development Expense											0		0		0
Costs and Expenses											803		633		522
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											218		320		306
Equity in (losses)/earnings of unconsolidated affiliates											37		26		17
Other than Temporary Impairment Losses, Investments											0		0
Other Nonoperating Income (Expense)											3		3		6
Gain (Loss) on Extinguishment of Debt											0		(9)		(1)
Gain on Sale of Investments													0		0
Interest expense											274		263		216
(Loss)/income before income taxes											(16)		77		112
Income tax expense											(1)		12		4
Net (Loss)/Income											(15)		65		108
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(54)		19		16
Net (loss)/income attributable to NRG Energy, Inc.											39		46		92
Operating revenues include inter-segment sales and net derivative gains and losses of:											8		29		12
Balance sheet
Equity investments in affiliates	710					697					710		697
Capital expenditures	23	[6]				30	[7]				23	[6]	30	[7]
Goodwill						0							0
Total assets	8,383					8,689					8,383		8,689
Segment Recast [Member] | Corporate
Income Statement
Operating revenues											77	[8]	39	[9]	19	[10]
Cost of revenue including selling marketing and general administrative											212		291		151
Depreciation and amortization											63		59		35
Asset Impairment Charges											33		132		(22)
Acquisition-related transaction and integration costs											7		6		76
Research and Development Expense											24		63		35
Costs and Expenses											339		551		275
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											(78)				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											(340)		(512)		(256)
Equity in (losses)/earnings of unconsolidated affiliates											7		0		0
Other than Temporary Impairment Losses, Investments											21		42
Other Nonoperating Income (Expense)											62		78		75
Gain (Loss) on Extinguishment of Debt											(142)		84		(93)
Gain on Sale of Investments													(14)		0
Interest expense											658		779		806
(Loss)/income before income taxes											(1,092)		(1,185)		(1,080)
Income tax expense											37		1,347		(5)
Net (Loss)/Income											(1,129)		(2,532)		(1,075)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											16		(37)		5
Net (loss)/income attributable to NRG Energy, Inc.											(1,145)		(2,495)		(1,080)
Operating revenues include inter-segment sales and net derivative gains and losses of:											189		212		85
Balance sheet
Equity investments in affiliates	91					127					91		127
Capital expenditures	110	[6]				246	[7]				110	[6]	246	[7]
Goodwill	111					111					111		111
Total assets	15,590					19,720					15,590		19,720
Segment Recast [Member] | Eliminations
Income Statement
Operating revenues											(1,179)		(1,170)		(2,004)
Cost of revenue including selling marketing and general administrative											(1,184)		(1,149)		(2,058)
Depreciation and amortization											0		0		0
Asset Impairment Charges											0		22		0
Acquisition-related transaction and integration costs											0		0		0
Research and Development Expense											0		0		0
Costs and Expenses											(1,184)		(1,127)		(2,058)
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											5		(43)		54
Equity in (losses)/earnings of unconsolidated affiliates											18		(9)		2
Other than Temporary Impairment Losses, Investments											0		0
Other Nonoperating Income (Expense)											(61)		(98)		(99)
Gain (Loss) on Extinguishment of Debt											0		0		0
Gain on Sale of Investments													0		0
Interest expense											(59)		(95)		(96)
(Loss)/income before income taxes											21		(55)		53
Income tax expense											0		0		0
Net (Loss)/Income											21		(55)		53
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(66)		(42)		(24)
Net (loss)/income attributable to NRG Energy, Inc.											87		(13)		77
Operating revenues include inter-segment sales and net derivative gains and losses of:											0		0		0
Balance sheet
Equity investments in affiliates	(257)					(247)					(257)		(247)
Capital expenditures	0	[6]				0	[7]				0	[6]	0	[7]
Goodwill						0							0
Total assets	(14,131)					(20,311)					(14,131)		(20,311)
Segment Recast [Member] | Generation [Member]
Income Statement
Operating revenues											5,679	[8]	7,546	[9]	9,288	[10]
Cost of revenue including selling marketing and general administrative											4,922		6,210		6,985
Depreciation and amortization											702		896		957
Asset Impairment Charges											645		4,827		87
Acquisition-related transaction and integration costs											0		0		1
Research and Development Expense											22		27		12
Costs and Expenses											6,291		11,960		8,042
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											294				19
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													21
Operating Income (Loss)											(318)		(4,393)		1,265
Equity in (losses)/earnings of unconsolidated affiliates											(5)		10		23
Other than Temporary Impairment Losses, Investments											142		14
Other Nonoperating Income (Expense)											36		48		39
Gain (Loss) on Extinguishment of Debt											0		0		0
Gain on Sale of Investments													0		18
Interest expense											79		97		94
(Loss)/income before income taxes											(508)		(4,446)		1,251
Income tax expense											(1)		0		3
Net (Loss)/Income											(507)		(4,446)		1,248
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											0		0		(1)
Net (loss)/income attributable to NRG Energy, Inc.											(507)		(4,446)		1,249
Operating revenues include inter-segment sales and net derivative gains and losses of:											955		898		1,873
Balance sheet
Equity investments in affiliates	204					334					204		334
Capital expenditures	767	[6]				792	[7]				767	[6]	792	[7]
Goodwill	199					536					199		536
Total assets	13,256					17,625					13,256		17,625
Segment Recast [Member] | Retail [Member]
Income Statement
Operating revenues											6,336	[8]	6,914	[9]	7,393	[10]
Cost of revenue including selling marketing and general administrative											5,169		6,113		7,270
Depreciation and amortization											115		133		134
Asset Impairment Charges											1		36		0
Acquisition-related transaction and integration costs											0		1		3
Research and Development Expense											4		4		1
Costs and Expenses											5,289		6,287		7,408
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											(1)				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											1,046		627		(15)
Equity in (losses)/earnings of unconsolidated affiliates											0		0		0
Other than Temporary Impairment Losses, Investments											0		0
Other Nonoperating Income (Expense)											1		(1)		0
Gain (Loss) on Extinguishment of Debt											0		0		0
Gain on Sale of Investments													0		0
Interest expense											1		1		2
(Loss)/income before income taxes											1,046		625		(17)
Income tax expense											1		1		1
Net (Loss)/Income											1,045		624		(18)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											0		0		0
Net (loss)/income attributable to NRG Energy, Inc.											1,045		624		(18)
Operating revenues include inter-segment sales and net derivative gains and losses of:											4		6		7
Balance sheet
Equity investments in affiliates	0					0					0		0
Capital expenditures	12	[6]				36	[7]				12	[6]	36	[7]
Goodwill	340					340					340		340
Total assets	1,977					2,017					1,977		2,017
Segment Recast [Member] | Renewables [Member]
Income Statement
Operating revenues											417	[8]	392	[9]	344	[10]
Cost of revenue including selling marketing and general administrative											215		185		191
Depreciation and amortization											190		181		164
Asset Impairment Charges											56		13		32
Acquisition-related transaction and integration costs											0		0		0
Research and Development Expense											40		52		40
Costs and Expenses											501		431		427
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments													0
Operating Income (Loss)											(84)		(39)		(83)
Equity in (losses)/earnings of unconsolidated affiliates											(30)		9		(4)
Other than Temporary Impairment Losses, Investments											105		0
Other Nonoperating Income (Expense)											1		3		1
Gain (Loss) on Extinguishment of Debt											0		0		(1)
Gain on Sale of Investments													0		0
Interest expense											108		83		97
(Loss)/income before income taxes											(326)		(110)		(184)
Income tax expense											(20)		(18)		0
Net (Loss)/Income											(306)		(92)		(184)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(13)		6		2
Net (loss)/income attributable to NRG Energy, Inc.											(293)		(98)		(186)
Operating revenues include inter-segment sales and net derivative gains and losses of:											23		25		$ 25
Balance sheet
Equity investments in affiliates	372					134					372		134
Capital expenditures	330	[6]				163	[7]				330	[6]	163	[7]
Goodwill	12					12					12		12
Total assets	$ 5,280					$ 5,142					$ 5,280		$ 5,142
[1]	Includes accruals.
[2]	Includes accruals.
[3]	(a) Inter-segment sales and net derivative gains and losses included in operating revenues$893 $2 $23 $8 $191 $— $1,117
[4]	(a) Inter-segment sales and net derivative gains and losses included in operating revenues$898 $6 $25 $29 $213 $— $1,171
[5]	(a) Inter-segment sales and net derivative gains and losses included in operating revenues$1,873 $7 $25 $12 $85 $— $2,002
[6]	Includes accruals.
[7]	Includes accruals.
[8]	(a) Inter-segment sales and net derivative gains and losses included in operating revenues$955 $4 $23 $8 $189 $— $1,179
[9]	(a) Inter-segment sales and net derivative gains and losses included in operating revenues$898 $6 $25 $29 $212 $— $1,170
[10]	(a) Inter-segment sales and net derivative gains and losses included in operating revenues$1,873 $7 $25 $12 $85 $— $2,002

Earnings Per Share (Details)

Earnings Per Share (Details) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares	Sep. 30, 2016USD ($)$ / sharesshares	Jun. 30, 2016USD ($)$ / sharesshares	Mar. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Sep. 30, 2015USD ($)$ / sharesshares	Jun. 30, 2015USD ($)$ / sharesshares	Mar. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Jun. 13, 2016	May 24, 2016
Temporary Equity, Redemption Percentage												1	1
Numerator:
Net (loss)/income attributable to NRG Energy, Inc.	$ (987)	$ 402	$ (271)	$ 82	$ (6,314)	$ 66	$ (14)	$ (120)	$ (774)	$ (6,382)	$ 134
Preferred Stock Dividends, Income Statement Impact									5	20	56
Redeemable Preferred Stock Dividends											9
Other Preferred Stock Dividends and Adjustments									0	0	47
Gain on Redemption of Redeemable Preferred Stock			78						(78)	0	0
(Loss)/Income Available for Common Stockholders	$ (987)	$ 402	$ (193)	$ 77	$ (6,319)	$ 61	$ (19)	$ (125)	$ (701)	$ (6,402)	$ 78
Denominator (Basic EPS):
Weighted average number of common shares outstanding | shares	316	316	315	315	315	331	333	336	316	329	334
Basic earnings per share:
(Loss)/Earnings per weighted average common share — basic | $ / shares	$ (3.13)	$ 1.27	$ (0.61)	$ 0.24	$ (20.08)	$ 0.18	$ (0.06)	$ 0.37	$ (2.22)	$ (19.46)	$ 0.23
Denominator (Diluted EPS):
Incremental shares attributable to the issuance of equity compensation (treasury stock method) | shares									0	0	5
Total dilutive shares | shares	316	317	315	315	315	332	333	336	316	329	339
Diluted earnings per share:
(Loss)/Earnings per weighted average common share — diluted | $ / shares	$ (3.13)	$ 1.27	$ (0.61)	$ 0.24	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ (2.22)	$ (19.46)	$ 0.23

Income Taxes (Provision - Detai

Income Taxes (Provision - Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current
State	$ 17	$ 6	$ 8
Total — current	17	6	8
Deferred
U.S. Federal	3	1,020	(50)
State	(6)	315	41
Foreign	2	1	4
Total — deferred	(1)	1,336	(5)
Income tax expense/(benefit)	$ 16	$ 1,342	$ 3
Effective income tax rate (as a percent)	(1.80%)	(26.30%)	2.20%
Domestic and foreign components of income from continuing operations before income tax expense
U.S.	$ (886)	$ (5,105)	$ 126
Foreign	11	11	9
Income/(loss) before income taxes	$ 875	$ 5,094	$ (135)
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	$ 875	$ 5,094	$ (135)
Tax at 35%	(306)	(1,783)	47
State taxes	11	(218)	9
Foreign operations	10	1	1
Federal and state tax credits, excluding PTCs	0	(5)	(1)
Valuation allowance	306	3,039	6
Impact of non-taxable equity earnings	22	(10)	(11)
Book goodwill impairment	0	(340)	0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	1	(3)	(2)
Production tax credit	(26)	(33)	(48)
Recognition of uncertain tax benefits	2	(15)	(30)
Effective Income Tax Rate Reconciliation, Tax Expense Attributable to Partnerships	(1)	12	4
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	1	19	22
Other	(4)	(2)	6
Income tax expense/(benefit)	$ 16	$ 1,342	$ 3
Effective income tax rate (as a percent)	(1.80%)	(26.30%)	2.20%

Earnings Per Share Earnings Per

Earnings Per Share Earnings Per Share (Details 2) (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5	22	17
Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	16	16
Stock Compensation Plan [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5	6	1
Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred Stock, Dividend Rate Amended, Percentage	2.822%	2.822%	2.822%

Income Taxes (Deferred Taxes Re

Income Taxes (Deferred Taxes Rec - Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets and valuation allowance
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	35.00%	35.00%
Deferred tax liabilities:
Deferred Tax Liabilities, Emissions Allowances	$ 30	$ 31
Derivatives, net	0	22
Cumulative translation adjustments	11	2
Investment in projects	(374)	(838)
Total deferred tax liabilities	415	893
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	318	255
Discount/premium on notes	45	68
Deferred Tax Assets, Property, Plant and Equipment	1,511	1,210
Deferred Tax Assets, Goodwill and Intangible Assets	83	39
Differences between book and tax basis of contracts	301	516
Pension and other postretirement benefits	183	218
Equity compensation	11	50
Bad debt reserve	12	6
U.S. capital loss carryforwards	1	1
U.S. Federal net operating loss carryforwards	1,171	1,373
Foreign net operating loss carryforwards	63	59
State net operating loss carryforwards	223	230
Foreign capital loss carryforwards	1	1
Deferred financing costs	4	6
Federal and state tax credit carryforwards	446	439
Federal benefit on state uncertain tax positions	12	17
Deferred Tax Assets, Intangibles	211	90
Deferred Tax Assets, Derivative Instruments	101	0
Deferred Tax Assets, Inventory	31	27
Deferred Tax Assets, Other	8	11
Total deferred tax assets	4,736	4,616
Valuation allowance	(4,116)	(3,575)
Total deferred tax assets, net of valuation allowance	620	1,041
Net deferred tax asset	205	148
NRG's net deferred tax position
Net deferred tax asset — noncurrent	225	167
Deferred Tax Liabilities, Net, Noncurrent	$ (20)	$ (19)

Income Taxes (DTA, Val Allowanc

Income Taxes (DTA, Val Allowance, and Tax Pay/Rec - Details 3) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Taxes receivable and payable
Deferred Tax Assets, Net of Valuation Allowance	$ 4,300	$ 3,700
Deferred Tax Assets, Valuation Allowance	4,116	3,575
Deferred Tax Assets, Net	205	148
Foreign net operating loss carryforwards	63	59
Foreign capital loss carryforwards	1	$ 1
Current taxes payable	8
Current taxes receivable	29
Domestic Tax Authority
Taxes receivable and payable
Operating Loss Carryforwards	1,200
State and Local Jurisdiction
Taxes receivable and payable
Deferred Tax Assets, Valuation Allowance	504
Operating Loss Carryforwards	223
Foreign Tax Authority
Taxes receivable and payable
Operating Loss Carryforwards	63
Federal Tax Authority [Member]
Taxes receivable and payable
Deferred Tax Assets, Valuation Allowance	3,600
New York State Empire Zone [Member]
Taxes receivable and payable
Current taxes receivable	10
State and Local Jurisdiction
Taxes receivable and payable
Current taxes receivable	11
Federal Cash Grant [Member]
Taxes receivable and payable
Current taxes receivable	$ 8

Income Taxes (Uncertain Tax Ben

Income Taxes (Uncertain Tax Benefits) (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Uncertain tax benefits
Liability for Uncertainty in Income Taxes, Noncurrent	$ 37	$ 35
Unrecognized Tax Benefits, Income Tax Penalties Expense	1
Accrued interest and penalties related to unrecognized tax benefits	4	3
Uncertain tax benefits reconciliation
Balance as of January 1	32	71
Increase due to current year positions	8	4
Decrease due to prior year positions	0	(25)
Unrecognized Tax Benefits, Increase Resulting from Acquisition	(6)	(18)
Uncertain tax benefits as of December 31	$ 34	$ 32

Stock-Based Compensation Stock-

Stock-Based Compensation Stock-Based Compensation (Intro) (Details) - shares	Dec. 31, 2016	Dec. 31, 2015
NRG LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	22,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	7,487,058	6,240,648
NRG GenOn LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized		5,558,390
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	960,904	1,671,633

Stock-Based Compensation (NQSO

Stock-Based Compensation (NQSO - Details 2) - Non-Qualified Stock Options [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	0	0	0
NQSO activity and changes
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Options Outstanding - Maximum Contractual Term (in years)	10 years
Outstanding at the beginning of the period (in shares)	2,071,913
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	(548,994)
Exercised (in shares)	0
Outstanding at the end of the period (in shares)	1,522,919	2,071,913
Exercisable at the end of the period (in shares)	1,522,919
Weighted Average Exercise Price at the beginning of the period (in dollars per share)	$ 32.27
Forfeited - Weighted Average Exercise Price (in dollars per share)	52.34
Weighted Average Exercise Price at the end of the period (in dollars per share)	25.03	$ 32.27
Exercisable - Weighted Average Exercise Price (in dollars per share)	$ 25.03
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	3 years
Options Exercisable - Weighted Average Remaining Contractual Term (in years)	3 years	3 years
Options Outstanding - Aggregate Intrinsic Value	$ 0	$ 0
Options Exercisable - Aggregate Intrinsic Value	0
Weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from exercises of options
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	0	2	$ 7
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	$ 0	$ 9	$ 21

Stock-Based Compensation (RSU -

Stock-Based Compensation (RSU - Details 2) - Restricted Stock Units (RSUs) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	1,980,141	2,261,996
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 19.29	$ 27.59
Granted (in units)	1,226,957
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 11.54	$ 27.31	$ 29.90
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(592,163)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 22.91
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(916,649)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 26.07
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$ 11	$ 10	$ 26

Stock-Based Compensation (DSU -

Stock-Based Compensation (DSU - Details 3) - Deferred Stock Units - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock-Based Compensation
Balance outstanding at the beginning of the period (in units)	427,578
Balance outstanding at the beginning of the period, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$ 21.88
Granted (in units)	102,147
Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$ 16.85	$ 25.14	$ 35.63
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(76,051)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 18.37
Balance outstanding at the end of the period (in units)	453,674	427,578
Balance outstanding at the end of the period, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$ 21.54	$ 21.88
Aggregate intrinsic value for DSUs outstanding	$ 6	$ 5	$ 10
Aggregate intrinsic values for DSUs converted to common stock during the period	$ 1	$ 0	$ 1

Stock-Based Compensation Sto123

Stock-Based Compensation Stock-Based Compensation (MSUs - Details 4) - Market Stock Unit [Member] - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Description	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 the performance period, typically 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) three quarters of one share of common stock if the TSR has decreased by no more than 25% over the performance period; (ii) one share of common stock, if there is no change in TSR over the performance period; and (iii) two shares of common stock if the TSR increases 100% or more over the performance period. If there is more than a 25% reduction in TSR over the performance period, no common stock will be paid. If the TSR is between 75% and 100% over the performance period, shares awarded are interpolated. The value of the common stock on the date of grant is based on the closing price of NRG common stock on the date of grant.
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	1,282,588	1,980,157
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 21.47	$ 29.54
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	806,409
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 14.73	$ 26.68	$ 31.90
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	4,015
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 33.81
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(1,499,963)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 27.76
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	34.33%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.31%
Minimum [Member]
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate		24.08%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	3 years	1 year
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate		0.25%
Maximum [Member]
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate		25.20%
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		1.07%

Stock-Based Compensation Sto124

Stock-Based Compensation Stock-Based Compensation (Supplemental - Details 5) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock-Based Compensation
Payments Related to Tax Withholding for Share-based Compensation		$ 5	$ 21	$ 16
Allocated Share-based Compensation Expense		24	41	42
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		27
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense		(4)	(12)	(8)
Non-Qualified Stock Options [Member]
Stock-Based Compensation
Allocated Share-based Compensation Expense	[1]	0	0	1
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	[1]	$ 0
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	[1]	0 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
Restricted Stock Units (RSUs)
Stock-Based Compensation
Allocated Share-based Compensation Expense		$ 14	23	20
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 12
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		1 year 5 months 14 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
Deferred Stock Units
Stock-Based Compensation
Allocated Share-based Compensation Expense		$ 2	2	2
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 0
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		0 years
Market Stock Unit [Member]
Stock-Based Compensation
Allocated Share-based Compensation Expense		$ 3	16	19
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 7
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		1 year 6 months 16 days
Phantom Share Units (PSUs) [Member]
Stock-Based Compensation
Allocated Share-based Compensation Expense	[2]	$ 5	$ 0	$ 0
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	[2]	$ 8
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	[2]	1 year 3 months 20 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
[1]	All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2016 and 2015.
[2]	Phantom Restricted Stock Units, PRSUs, are liability-classified time-based awards that typically vest ratably over a three-year period. The amount to be paid upon vesting is based on NRG's closing stock price for the period.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transactions
Revenues from Related Parties Included in Operating Revenues	$ 7	$ 8	$ 12
Management Fees Revenue	11	11	10
Gladstone
Related Party Transactions
Revenues from Related Parties Included in Operating Revenues	2	4	6
GenConn
Related Party Transactions
Revenues from Related Parties Included in Operating Revenues	$ 5	$ 4	$ 6

Commitments and Contingencie126

Commitments and Contingencies (Operating Leases) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Coal, Gas and Transportation Commitments
Off-market Lease, Unfavorable		$ 1,040	$ 1,146
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals		$ 14
EME [Member]
Coal, Gas and Transportation Commitments
Leased Interest		100.00%
Off-market Lease, Unfavorable				$ 159
Lease expense		$ 14
GenOn Mid-Atlantic
Coal, Gas and Transportation Commitments
Leased Interest		100.00%
Off-market Lease, Unfavorable					$ 604
Lease expense		$ 43
Future commitments under coal, gas and transportation contractual agreements
Operating Leases, Future Minimum Payments Due, Next Twelve Months		144
Operating Leases, Future Minimum Payments, Due in Two Years		105
Operating Leases, Future Minimum Payments, Due in Three Years		139
Operating Leases, Future Minimum Payments, Due in Four Years		105
Operating Leases, Future Minimum Payments, Due in Five Years		42
Thereafter		400
Total		935
REMA [Member]
Coal, Gas and Transportation Commitments
Lease expense		29
Future commitments under coal, gas and transportation contractual agreements
Operating Leases, Future Minimum Payments Due, Next Twelve Months		63
Operating Leases, Future Minimum Payments, Due in Two Years		55
Operating Leases, Future Minimum Payments, Due in Three Years		65
Operating Leases, Future Minimum Payments, Due in Four Years		56
Operating Leases, Future Minimum Payments, Due in Five Years		47
Thereafter		231
Total		517
Other Leased Property [Member]
Coal, Gas and Transportation Commitments
Lease expense		102	$ 100	$ 106
Future commitments under coal, gas and transportation contractual agreements
Operating Leases, Future Minimum Payments Due, Next Twelve Months		84
Operating Leases, Future Minimum Payments, Due in Two Years		76
Operating Leases, Future Minimum Payments, Due in Three Years		67
Operating Leases, Future Minimum Payments, Due in Four Years		61
Operating Leases, Future Minimum Payments, Due in Five Years		52
Thereafter		443
Total	[1]	783
Powerton and Joliet [Member]
Future commitments under coal, gas and transportation contractual agreements
Operating Leases, Future Minimum Payments Due, Next Twelve Months		1
Operating Leases, Future Minimum Payments, Due in Two Years		1
Operating Leases, Future Minimum Payments, Due in Three Years		1
Operating Leases, Future Minimum Payments, Due in Four Years		1
Operating Leases, Future Minimum Payments, Due in Five Years		3
Thereafter		234
Total		$ 241
REMA [Member]
Coal, Gas and Transportation Commitments
Leased Interest		100.00%
REMA [Member] | Keystone [Member]
Coal, Gas and Transportation Commitments
Leased Interest		16.70%
REMA [Member] | Conemaugh [Member]
Coal, Gas and Transportation Commitments
Leased Interest		16.50%
REMA [Member] | Keystone Conemaugh
Coal, Gas and Transportation Commitments
Off-market Lease, Unfavorable					$ 186
[1]	Amounts in the table exclude future sublease income of $14 million associated with long-term leases for office locations.

Commitments and Contingencie127

Commitments and Contingencies (Commitments) (Details 2) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Minimum purchase commitment
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months		$ 25
Unrecorded Unconditional Purchase Obligation, Due within Two Years		17
Unrecorded Unconditional Purchase Obligation, Due within Three Years		13
Unrecorded Unconditional Purchase Obligation, Due within Four Years		11
Unrecorded Unconditional Purchase Obligation, Due within Five Years		21
Thereafter		0
Total	[1]	$ 87
Maximum remaining term under individual purchased power contract (in years)		5 years
Coal, Gas and Transportation Commitments
Commitments and Contingencies
Purchases		$ 1,800	$ 2,600	$ 3,500
Minimum purchase commitment
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months		638
Unrecorded Unconditional Purchase Obligation, Due within Two Years		251
Unrecorded Unconditional Purchase Obligation, Due within Three Years		174
Unrecorded Unconditional Purchase Obligation, Due within Four Years		140
Unrecorded Unconditional Purchase Obligation, Due within Five Years		109
Thereafter		415
Total		$ 1,727
[1]	As of December 31, 2016, the maximum remaining term under any individual purchased power contract is five years.

Commitments and Contingencie128

Commitments and Contingencies (Texas, Nuclear) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Guarantee Obligations, Estimated Exposure	$ 3,630,000	$ 2,878,000
Nuclear insurance liability limit per incident	13,440,000
Required nuclear liability insurance	450,000
Nuclear financial protection pool mandated by the Price-Anderson Act	13,000,000
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident	$ 127,000
Nuclear Insurance Financial Protection Pool, Maximum Assessment, Adminstrative Fee, As a Percent	5.00%
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident	$ 19,000
44% maximum assessment	44.00%
Nuclear Insurance Financial Protection Pool Nuclear Operator Maximum Annual Assessment	$ 8,000
Maximum liability per nuclear incident	112,000
Mutual property insurance additional blanket policy property coverage	1,250,000
Nuclear property insurance coverage limit per individual insured	1,500,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery	2,520
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	$ 1,980
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 months
Number of years board of directors of industry mutual insurance company can adjust policy after policy expires	6 years
Nuclear Event [Member]
Loss Contingencies [Line Items]
Total nuclear property insurance coverage	$ 2,750,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery	274,400
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	215,600
Non-nuclear Event [Member]
Loss Contingencies [Line Items]
Total nuclear property insurance coverage	1,500,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery	183,500
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	144,000
Lignite Contract with Texas Westmoreland Coal Co. [Member] | Guarantee of Indebtedness of Others [Member]
Loss Contingencies [Line Items]
Guarantee Obligations, Estimated Exposure	$ 95,500

Commitments and Contigencies (C

Commitments and Contigencies (Contingencies) (Details 4) - USD ($)		3 Months Ended	9 Months Ended	12 Months Ended
		Sep. 30, 2010	Sep. 30, 2016	Dec. 31, 2015	Dec. 31, 2016
Loss Contingencies
Environmental Projects			$ 1,000,000
MD Department of Environment v. Chalk Point [Member]
Loss Contingencies
Civil Penalties			1,000,000
Midwest Generation New Source Review [Member]
Loss Contingencies
Civil Penalties		$ 37,500
Telephone Consumer Protection Act Purported Class Actions [Member]
Loss Contingencies
Loss Contingency, Damages Sought, Value			$ 1,500
CDWR and SDGE v Sunrise Power [Member]
Loss Contingencies
Loss Contingency, Damages Sought, Value				$ 1,200,000
Remaining Term				70 months
GenOn Senior Notes Due in 2017 [Member] | Non Recourse Debt [Member]
Loss Contingencies
Debt Instrument, Interest Rate, Stated Percentage	[1]				7.875%
GenOn senior notes, due 2018 | Non Recourse Debt [Member]
Loss Contingencies
Debt Instrument, Interest Rate, Stated Percentage	[1]				9.50%
GenOn senior notes, due 2020 | Non Recourse Debt [Member]
Loss Contingencies
Debt Instrument, Interest Rate, Stated Percentage	[1]				9.875%
GenOn Americas Generation Senior Notes Due in 2021 [Member] | Non Recourse Debt [Member]
Loss Contingencies
Debt Instrument, Interest Rate, Stated Percentage	[1]				8.50%
GenOn Americas Generation senior notes, due 2031 | Non Recourse Debt [Member]
Loss Contingencies
Debt Instrument, Interest Rate, Stated Percentage	[1]				9.125%
[1]	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

Regulatory Matters (Details)

Regulatory Matters (Details) $ in Millions	1 Months Ended	12 Months Ended
	May 31, 2010orders	Dec. 31, 2016USD ($)	Jun. 30, 2015MW	Dec. 20, 2013USD ($)	Jul. 05, 2012USD ($)owners	Dec. 31, 2011USD ($)
Regulatory Assets [Line Items]
Out-of-market subsidy payments		$ 7,600
Out of Market Subsidy Payment term		12 years
Number of significant orders issued by FERC | orders	2
SECA charges owed by BP Energy						$ 22
Regulatory Charges Settled by Third Party					$ 24
Number of PJM Transmission Owners Who Filed Motion | owners					3
Regulatory Charges Settled by Third Party, Additional					$ 1
Genon [Member]
Regulatory Assets [Line Items]
Regulatory payments sought				$ 22
Carlsbad Energy Center [Member]
Regulatory Assets [Line Items]
Power Generation Capacity, Megawatts | MW			500

Cash Flow Information (Details)

Cash Flow Information (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Significant Noncash Transactions
Interest paid, net of amount capitalized		$ 1,106,000,000	$ 1,172,000,000	$ 1,067,000,000
Income taxes paid	[1]	27,000,000	16,000,000	(6,000,000)
Consent Fees Paid, Preferred Stock		0	0	5,000,000
(Decrease)/additions to fixed assets for accrued capital expenditures		(33,000,000)	(24,000,000)	87,000,000
Decrease to fixed assets for accrued grants and related tax impact		0	0	711,000,000
Income Taxes Paid		29,000,000	17,000,000	15,000,000
Income tax refunds received		2,000,000	1,000,000	21,000,000
EME [Member]
Other Significant Noncash Transactions
Issuance of shares for EME acquisition		$ 0	$ 0	$ (401,000,000)
[1]	In 2016, the net income taxes paid reflect $29 million in income taxes paid and $2 million in income tax refunds. In 2015, the net income taxes refunded are net of $17 million income taxes paid and $1 million income tax refunds. In 2014, the net income taxes refunded are net of $15 million income taxes paid and $21 million income tax refunds.

Guarantees (Details)

Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Guarantees [Abstract]
Fair value of guarantees	$ 2.2
Guarantor Obligations
Guarantees By Remaining Maturity, Under 1 Year	2,122
Guarantees By Remaining Maturity, 1-3 Years	500
Guarantees By Remaining Maturity, 3-5 Years	5
Guarantees By Remaining Maturity, Over 5 Years	1,003
Guarantees by Remaining Maturity, Total	3,630	$ 2,878
Letters of credit and surety bonds
Guarantor Obligations
Guarantees By Remaining Maturity, Under 1 Year	2,122
Guarantees By Remaining Maturity, 1-3 Years	80
Guarantees By Remaining Maturity, 3-5 Years	0
Guarantees By Remaining Maturity, Over 5 Years	15
Guarantees by Remaining Maturity, Total	$ 2,217	1,899
Letters of credit and surety bonds, maximum expiration period (in years)	1 year
Asset sales guarantee obligations
Guarantor Obligations
Guarantees By Remaining Maturity, Under 1 Year	$ 0
Guarantees By Remaining Maturity, 1-3 Years	420
Guarantees By Remaining Maturity, 3-5 Years	0
Guarantees By Remaining Maturity, Over 5 Years	257
Guarantees by Remaining Maturity, Total	677	257
Other guarantees
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	5
Guarantees By Remaining Maturity, Over 5 Years	731
Guarantees by Remaining Maturity, Total	$ 736	$ 722

Jointly Owned Plants (Details)

Jointly Owned Plants (Details) $ in Millions	Dec. 31, 2016USD ($)
South Texas Project
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	44.00%
Property, Plant and Equipment	$ 3,275
Accumulated Depreciation	(1,734)
Construction in Progress	$ 39
Big Cajun II Unit 3, New Roads, LA
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	58.00%
Property, Plant and Equipment	$ 204
Accumulated Depreciation	123
Construction in Progress	$ 0
Cedar Bayou Unit 4, Baytown, TX
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	50.00%
Property, Plant and Equipment	$ 216
Accumulated Depreciation	(67)
Construction in Progress	$ 5
Keystone [Member]
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	3.70%
Property, Plant and Equipment	$ 97
Accumulated Depreciation	(48)
Construction in Progress	$ 0
Conemaugh, New Florence, PA
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	3.72%
Property, Plant and Equipment	$ 103
Accumulated Depreciation	(51)
Construction in Progress	$ 1

Unaudited Quarterly Financia134

Unaudited Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 2,532	$ 3,952	$ 2,638	$ 3,229	$ 3,011	$ 4,434	$ 3,400	$ 3,829	$ 12,351	$ 14,674	$ 15,868
Operating Income (Loss)	(791)	755	87	476	(4,727)	379	232	76	527	(4,040)	1,271
Net (Loss)/Income	(1,055)	393	(276)	47	(6,358)	67	(9)	(136)	(891)	(6,436)	132
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(68)	(9)	(5)	(35)	(44)	1	5	(16)	(117)	(54)	(2)
Net (loss)/income attributable to NRG Energy, Inc.	(987)	402	(271)	82	(6,314)	66	(14)	(120)	(774)	(6,382)	134
Net Income (Loss) Available to Common Stockholders, Basic	$ (987)	$ 402	$ (193)	$ 77	$ (6,319)	$ 61	$ (19)	$ (125)	$ (701)	$ (6,402)	$ 78
Weighted average number of common shares outstanding — basic	316	316	315	315	315	331	333	336	316	329	334
Net (Loss)/Income per Weighted Average Common Share — Basic	$ (3.13)	$ 1.27	$ (0.61)	$ 0.24	$ (20.08)	$ 0.18	$ (0.06)	$ 0.37	$ (2.22)	$ (19.46)	$ 0.23
Weighted average number of common shares outstanding — diluted	316	317	315	315	315	332	333	336	316	329	339
Net (Loss)/Income per Weighted Average Common Share — Diluted	$ (3.13)	$ 1.27	$ (0.61)	$ 0.24	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ (2.22)	$ (19.46)	$ 0.23

Condensed Consolidating Fina135

Condensed Consolidating Financial Information (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument
Long-term Debt	$ 19,406	$ 19,620
Recourse Debt
Debt Instrument
Long-term Debt	7,786	$ 8,584
Senior Notes [Member] | Recourse Debt
Debt Instrument
Long-term Debt	$ 5,400

Condensed Consolidating Fina136

Condensed Consolidating Financial Information (Statements of Operations) (Details 2) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Operating Revenues
Total operating revenues		$ 2,532	$ 3,952	$ 2,638	$ 3,229	$ 3,011	$ 4,434	$ 3,400	$ 3,829	$ 12,351		$ 14,674		$ 15,868
Operating Costs and Expenses
Cost of operations										8,555		10,784		11,808
Depreciation and amortization										1,367		1,566		1,523
Impairment losses										918		5,030		97
Selling, general and administrative										1,101		1,199		1,016
Acquisition related transactions and integration costs										8		10		84
Research and Development Expense										90		146		88
Total operating costs and expenses										12,039		18,735		14,616
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal										215		0		19
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments										0		(21)		0
Operating Income (Loss)		(791)	755	87	476	(4,727)	379	232	76	527		(4,040)		1,271
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries										0		0		0
Equity in earnings of unconsolidated affiliates										27		36		38
Impairment losses on investments										(268)		(56)		0
Other income, net										42		33		22
(Loss)/gain on sale of equity method investment										0		(14)		18
Loss on debt extinguishment										(142)		75		(95)
Interest expense										(1,061)		(1,128)		(1,119)
Total other expense										(1,402)		(1,054)		(1,136)
(Loss)/income before income taxes										(875)		(5,094)		135
Income tax expense										16		1,342		3
Net (Loss)/Income		(1,055)	393	(276)	47	(6,358)	67	(9)	(136)	(891)		(6,436)		132
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests		(68)	(9)	(5)	(35)	(44)	1	5	(16)	(117)		(54)		(2)
Net (loss)/income attributable to NRG Energy, Inc.		$ (987)	$ 402	$ (271)	$ 82	$ (6,314)	$ 66	$ (14)	$ (120)	(774)		(6,382)		134
Guarantor Subsidiaries
Operating Revenues
Total operating revenues										7,509		10,024		9,974
Operating Costs and Expenses
Cost of operations										5,402		7,712		7,909
Depreciation and amortization										565		787		801
Impairment losses										378		4,655		0
Selling, general and administrative										415		467		333
Acquisition related transactions and integration costs										0		1		3
Research and Development Expense										0		0		0
Total operating costs and expenses										6,760		13,622		9,046
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal										0				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments												0
Operating Income (Loss)										749		(3,598)		928
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries										(148)		(86)		317
Equity in earnings of unconsolidated affiliates										5		8		13
Impairment losses on investments										0		0
Other income, net										4		4		7
(Loss)/gain on sale of equity method investment												0		0
Loss on debt extinguishment										0		0		0
Interest expense										(15)		(18)		(19)
Total other expense										(154)		(92)		318
(Loss)/income before income taxes										595		(3,690)		1,246
Income tax expense										(1)		(1,104)		322
Net (Loss)/Income										596		(2,586)		924
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests										0		0		0
Net (loss)/income attributable to NRG Energy, Inc.										596		(2,586)		924
Non-Guarantor Subsidiaries
Operating Revenues
Total operating revenues										5,082		4,768		6,287
Operating Costs and Expenses
Cost of operations										3,355		3,176		4,220
Depreciation and amortization										776		759		706
Impairment losses										540		375		119
Selling, general and administrative										397		382		379
Acquisition related transactions and integration costs										1		(5)		15
Research and Development Expense										60		53		32
Total operating costs and expenses										5,129		4,740		5,471
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal										294				19
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments												(21)
Operating Income (Loss)										247		49		835
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries										(58)		(29)		219
Equity in earnings of unconsolidated affiliates										37		37		33
Impairment losses on investments										(268)		(25)
Other income, net										46		29		14
(Loss)/gain on sale of equity method investment												0		18
Loss on debt extinguishment										(4)		56		(9)
Interest expense										(574)		(564)		(525)
Total other expense										(821)		(496)		(250)
(Loss)/income before income taxes										(574)		(447)		585
Income tax expense										18		(96)		159
Net (Loss)/Income										(592)		(351)		426
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests										(103)		(23)		57
Net (loss)/income attributable to NRG Energy, Inc.										(489)		(328)		369
NRG Energy, Inc.
Operating Revenues
Total operating revenues										0		0		0
Operating Costs and Expenses
Cost of operations										42		14		4
Depreciation and amortization										26		20		16
Impairment losses										0		0		0
Selling, general and administrative										289		350		304
Acquisition related transactions and integration costs										7		14		66
Research and Development Expense										30		93		56
Total operating costs and expenses										394		491		446
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal										(79)				0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments												0
Operating Income (Loss)										(473)		(491)		(446)
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries										313		(2,799)		775
Equity in earnings of unconsolidated affiliates										(5)		0		0
Impairment losses on investments										0		(31)
Other income, net										(6)		0		3
(Loss)/gain on sale of equity method investment												(14)		0
Loss on debt extinguishment										(138)		19		(86)
Interest expense										(472)		(546)		(575)
Total other expense										(308)		(3,371)		117
(Loss)/income before income taxes										(781)		(3,862)		(329)
Income tax expense										(63)		2,489		(478)
Net (Loss)/Income										(718)		(6,351)		149
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests										56		31		15
Net (loss)/income attributable to NRG Energy, Inc.										(774)		(6,382)		134
Consolidation, Eliminations [Member]
Operating Revenues
Total operating revenues										(240)	[1]	(118)	[2]	(393)	[3]
Operating Costs and Expenses
Cost of operations										(244)	[1]	(118)	[2]	(325)	[3]
Depreciation and amortization										0	[1],[4]	0	[2],[5]	0	[3],[6]
Impairment losses										0	[1]	0	[2]	(22)	[3]
Selling, general and administrative										0	[1]	0	[2]	0	[3]
Acquisition related transactions and integration costs										0	[1]	0	[2]	0	[3]
Research and Development Expense										0	[1]	0	[2]	0	[3]
Total operating costs and expenses										(244)	[1]	(118)	[2]	(347)	[3]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal										0	[1]			0	[3]
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	[2],[5]											0
Operating Income (Loss)										4	[1]	0	[2]	(46)	[3]
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries										(107)	[1]	2,914	[2]	(1,311)	[3]
Equity in earnings of unconsolidated affiliates										(10)	[1],[4]	(9)	[2],[5]	(8)	[3],[6]
Impairment losses on investments										0	[1]	0	[2]
Other income, net										(2)	[1]	0	[2]	(2)	[3]
(Loss)/gain on sale of equity method investment												0	[2]	0	[3]
Loss on debt extinguishment										0	[1]	0	[2]	0	[3]
Interest expense										0	[1]	0	[2]	0	[3]
Total other expense										(119)	[1]	2,905	[2]	(1,321)	[3]
(Loss)/income before income taxes										(115)	[1]	2,905	[2]	(1,367)	[3]
Income tax expense										62	[1]	53	[2]	0	[3]
Net (Loss)/Income										(177)	[1],[4]	2,852	[2],[5]	(1,367)	[3],[6]
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests										(70)	[1]	(62)	[2]	(74)	[3]
Net (loss)/income attributable to NRG Energy, Inc.										$ (107)	[1]	$ 2,914	[2]	$ (1,293)	[3]
[1]	All significant intercompany transactions have been eliminated in consolidation.
[2]	All significant intercompany transactions have been eliminated in consolidation.
[3]	All significant intercompany transactions have been eliminated in consolidation.
[4]	All significant intercompany transactions have been eliminated in consolidation.
[5]	All significant intercompany transactions have been eliminated in consolidation.
[6]	All significant intercompany transactions have been eliminated in consolidation.

Condensed Consolidating Fina137

Condensed Consolidating Financial Information (Statements of Comprehensive Income) (Details 3) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Net (Loss)/Income		$ (1,055)	$ 393	$ (276)	$ 47	$ (6,358)	$ 67	$ (9)	$ (136)	$ (891)		$ (6,436)		$ 132
Unrealized gain on derivatives, net										35		(15)		(45)
Foreign currency translation adjustments, net										(1)		(11)		(8)
Available-for-sale securities, net										1		17		(7)
Defined benefit plan, net										3		10		(129)
Other comprehensive income/(loss)										38		1		(189)
Comprehensive income/(loss)										(853)		(6,435)		(57)
Less: Comprehensive income/(loss) attributable to noncontrolling interest										(117)		(73)		8
Comprehensive income/(loss) attributable to NRG Energy, Inc.										(736)		(6,362)		(65)
Preferred Stock Dividends, Income Statement Impact										5		20		56
Gain on Redemption of Redeemable Preferred Stock				$ 78						(78)		0		0
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders										(663)		(6,382)		(121)
Guarantor Subsidiaries
Net (Loss)/Income										596		(2,586)		924
Unrealized gain on derivatives, net										0		(9)		(49)
Foreign currency translation adjustments, net										(1)		0		0
Available-for-sale securities, net										0		0		0
Defined benefit plan, net										36		22		5
Other comprehensive income/(loss)										35		(31)		(44)
Comprehensive income/(loss)										631		(2,617)		880
Less: Comprehensive income/(loss) attributable to noncontrolling interest										0		0		0
Comprehensive income/(loss) attributable to NRG Energy, Inc.										631		(2,617)		880
Preferred Stock Dividends, Income Statement Impact										0		0		0
Gain on Redemption of Redeemable Preferred Stock										0
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders										631		(2,617)		880
Non-Guarantor Subsidiaries
Net (Loss)/Income										(592)		(351)		426
Unrealized gain on derivatives, net										32		(13)		(89)
Foreign currency translation adjustments, net										(1)		(7)		(12)
Available-for-sale securities, net										0		(1)		1
Defined benefit plan, net										(23)		15		(104)
Other comprehensive income/(loss)										8		(36)		(204)
Comprehensive income/(loss)										(584)		(387)		222
Less: Comprehensive income/(loss) attributable to noncontrolling interest										(103)		(42)		67
Comprehensive income/(loss) attributable to NRG Energy, Inc.										(481)		(345)		155
Preferred Stock Dividends, Income Statement Impact										0		0		0
Gain on Redemption of Redeemable Preferred Stock										0
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders										(481)		(345)		155
NRG Energy, Inc.
Net (Loss)/Income										(718)		(6,351)		149
Unrealized gain on derivatives, net										89		48		(215)
Foreign currency translation adjustments, net										(1)		(4)		4
Available-for-sale securities, net										1		18		(8)
Defined benefit plan, net										(51)		42		20
Other comprehensive income/(loss)										38		20		(199)
Comprehensive income/(loss)										(680)		(6,331)		(50)
Less: Comprehensive income/(loss) attributable to noncontrolling interest										56		31		15
Comprehensive income/(loss) attributable to NRG Energy, Inc.										(736)		(6,362)		(65)
Preferred Stock Dividends, Income Statement Impact										5		20		56
Gain on Redemption of Redeemable Preferred Stock										(78)
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders										(663)		(6,382)		(121)
Consolidation, Eliminations [Member]
Net (Loss)/Income										(177)	[1],[2]	2,852	[3],[4]	(1,367)	[5],[6]
Unrealized gain on derivatives, net										(86)	[7]	(41)	[8]	308	[9]
Foreign currency translation adjustments, net										2	[7]	0	[8]	0	[9]
Available-for-sale securities, net										0	[7]	0	[8]	0	[9]
Defined benefit plan, net										41	[7]	(89)	[8]	(50)	[9]
Other comprehensive income/(loss)										(43)	[7]	48	[8]	258	[9]
Comprehensive income/(loss)										(220)	[7]	2,900	[8]	(1,109)	[9]
Less: Comprehensive income/(loss) attributable to noncontrolling interest										(70)	[7]	(62)	[8]	(74)	[9]
Comprehensive income/(loss) attributable to NRG Energy, Inc.										(150)	[7]	2,962	[8]	(1,035)	[9]
Preferred Stock Dividends, Income Statement Impact										0	[7]	0	[8]	0	[9]
Gain on Redemption of Redeemable Preferred Stock	[7]									0
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders										$ (150)	[7]	$ 2,962	[8]	$ (1,035)	[9]
[1]	All significant intercompany transactions have been eliminated in consolidation.
[2]	All significant intercompany transactions have been eliminated in consolidation.
[3]	All significant intercompany transactions have been eliminated in consolidation.
[4]	All significant intercompany transactions have been eliminated in consolidation.
[5]	All significant intercompany transactions have been eliminated in consolidation.
[6]	All significant intercompany transactions have been eliminated in consolidation.
[7]	All significant intercompany transactions have been eliminated in consolidation.
[8]	All significant intercompany transactions have been eliminated in consolidation.
[9]	All significant intercompany transactions have been eliminated in consolidation.

Condensed Consolidating Fina138

Condensed Consolidating Financial Information (Balance Sheets) (Details 4) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014		Jun. 13, 2016	Dec. 31, 2013
Current Assets
Cash and cash equivalents		$ 1,973		$ 1,518		$ 2,116			$ 2,254
Funds deposited by counterparties		2		106
Restricted cash		446		414
Accounts receivable - trade, net		1,166		1,157
Due from Affiliate, Current		6		4
Inventory		1,111		1,252
Derivative instruments		1,062		1,915
Derivative, Collateral, Right to Reclaim Cash		203		568
Disposal Group, Including Discontinued Operation, Other Assets, Current		9		6
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		417		451
Total current assets		6,395		7,391
Net Property, Plant and Equipment		17,912		18,732
Other Assets
Investment in subsidiaries		0		0
Equity investments in affiliates		1,120		1,045
Notes receivable, less current portion		17		53
Goodwill		662		999
Intangible assets, net		2,036		2,310
Nuclear decommissioning trust fund		610		561
Deferred income taxes		225		167
Derivative instruments		189		305
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		10		105
Other non-current assets		1,179		1,214
Total other assets		6,048		6,759
Total assets		30,355		32,882
Current Liabilities
Current portion of long-term debt and capital leases		1,220		481
Accounts payable		895		869
Accounts payable - affiliate		0		0
Derivative instruments		1,084		1,721
Cash collateral received in support of energy risk management activities		2		106
Accrued interest expense		220		242
Other accrued expenses		543		568
Disposal Group, Including Discontinued Operation, Liabilities, Current		0		2
Other current liabilities		418		386
Total current liabilities		4,382		4,375
Other Liabilities
Long-term debt and capital leases		18,006		18,983
Nuclear decommissioning reserve		287		326
Nuclear decommissioning trust liability		339		283
Postretirement and other benefit obligations		553		588
Deferred income taxes		20		19
Derivative instruments		294		493
Off-market Lease, Unfavorable		1,040		1,146
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		12		4
Other non-current liabilities		930		900
Total non-current liabilities		21,481		22,742
Total Liabilities		25,863		27,117
Redeemable noncontrolling interest in subsidiaries		0		302		291		$ 304	249
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		46		29		19			2
Stockholders' Equity		4,446		5,434		11,676			10,467
Total Liabilities and Stockholders' Equity		30,355		32,882
Guarantor Subsidiaries
Current Assets
Cash and cash equivalents		0		0		18			56
Funds deposited by counterparties		2		55
Restricted cash		11		5
Accounts receivable - trade, net		734		851
Due from Affiliate, Current		309		395
Inventory		482		570
Derivative instruments		962		1,202
Derivative, Collateral, Right to Reclaim Cash		37		474
Disposal Group, Including Discontinued Operation, Other Assets, Current		0		0
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		76		93
Total current assets		2,613		3,645
Net Property, Plant and Equipment		4,216		4,767
Other Assets
Investment in subsidiaries		837		842
Equity investments in affiliates		(14)		(14)
Notes receivable, less current portion		0		0
Goodwill		359		697
Intangible assets, net		592		763
Nuclear decommissioning trust fund		610		561
Deferred income taxes		3		(6)
Derivative instruments		143		153
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		0		0
Other non-current assets		67		80
Total other assets		2,597		3,076
Total assets		9,426		11,488
Current Liabilities
Current portion of long-term debt and capital leases		0		2
Accounts payable		499		553
Accounts payable - affiliate		655		151
Derivative instruments		947		1,130
Cash collateral received in support of energy risk management activities		2		55
Accrued interest expense		3		5
Other accrued expenses		110		122
Disposal Group, Including Discontinued Operation, Liabilities, Current				0
Other current liabilities		204		192
Total current liabilities		2,420		2,210
Other Liabilities
Long-term debt and capital leases		244		302
Nuclear decommissioning reserve		287		326
Nuclear decommissioning trust liability		339		283
Postretirement and other benefit obligations		114		236
Deferred income taxes		186		179
Derivative instruments		157		301
Off-market Lease, Unfavorable		80		95
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		0		0
Other non-current liabilities		283		318
Total non-current liabilities		1,690		2,040
Total Liabilities		4,110		4,250
Redeemable noncontrolling interest in subsidiaries		0		0
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		0		0
Stockholders' Equity		5,316		7,238
Total Liabilities and Stockholders' Equity		9,426		11,488
Non-Guarantor Subsidiaries
Current Assets
Cash and cash equivalents		1,650		825		1,455			870
Funds deposited by counterparties		0		51
Restricted cash		435		409
Accounts receivable - trade, net		429		304
Due from Affiliate, Current		(241)		260
Inventory		629		682
Derivative instruments		305		871
Derivative, Collateral, Right to Reclaim Cash		166		94
Disposal Group, Including Discontinued Operation, Other Assets, Current		9		6
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		279		287
Total current assets		3,661		3,789
Net Property, Plant and Equipment		13,472		13,773
Other Assets
Investment in subsidiaries		1,973		2,244
Equity investments in affiliates		1,129		1,160
Notes receivable, less current portion		17		46
Goodwill		303		302
Intangible assets, net		1,447		1,551
Nuclear decommissioning trust fund		0		0
Deferred income taxes		868		815
Derivative instruments		60		184
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		10		105
Other non-current assets		784		749
Total other assets		6,591		7,156
Total assets		23,724		24,718
Current Liabilities
Current portion of long-term debt and capital leases		1,202		460
Accounts payable		362		277
Accounts payable - affiliate		1,834		2,000
Derivative instruments		342		749
Cash collateral received in support of energy risk management activities		0		51
Accrued interest expense		94		91
Other accrued expenses		140		151
Disposal Group, Including Discontinued Operation, Liabilities, Current				2
Other current liabilities		166		187
Total current liabilities		4,140		3,968
Other Liabilities
Long-term debt and capital leases		10,302		10,496
Nuclear decommissioning reserve		0		0
Nuclear decommissioning trust liability		0		0
Postretirement and other benefit obligations		189		200
Deferred income taxes		(1,094)		(1,088)
Derivative instruments		187		224
Off-market Lease, Unfavorable		960		1,051
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		12		4
Other non-current liabilities		573		535
Total non-current liabilities		11,129		11,422
Total Liabilities		15,269		15,390
Redeemable noncontrolling interest in subsidiaries		0		0
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		46		29
Stockholders' Equity		8,409		9,299
Total Liabilities and Stockholders' Equity		23,724		24,718
NRG Energy, Inc.
Current Assets
Cash and cash equivalents		323		693		$ 643			1,328
Funds deposited by counterparties		0		0
Restricted cash		0		0
Accounts receivable - trade, net		3		2
Due from Affiliate, Current		200		571
Inventory		0		0
Derivative instruments		0		0
Derivative, Collateral, Right to Reclaim Cash		0		0
Disposal Group, Including Discontinued Operation, Other Assets, Current		0		0
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		62		71
Total current assets		588		1,337
Net Property, Plant and Equipment		251		219
Other Assets
Investment in subsidiaries		10,128		11,039
Equity investments in affiliates		5		1
Notes receivable, less current portion		(76)		7
Goodwill		0		0
Intangible assets, net		0		2
Nuclear decommissioning trust fund		0		0
Deferred income taxes		(646)		(642)
Derivative instruments		36		0
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		0		0
Other non-current assets		328		385
Total other assets		9,775		10,792
Total assets		10,614		12,348
Current Liabilities
Current portion of long-term debt and capital leases		(58)		19
Accounts payable		34		39
Accounts payable - affiliate		(2,227)		(929)
Derivative instruments		0		0
Cash collateral received in support of energy risk management activities		0		0
Accrued interest expense		123		147
Other accrued expenses		293		295
Disposal Group, Including Discontinued Operation, Liabilities, Current				0
Other current liabilities		48		7
Total current liabilities		(1,787)		(422)
Other Liabilities
Long-term debt and capital leases		7,460		8,185
Nuclear decommissioning reserve		0		0
Nuclear decommissioning trust liability		0		0
Postretirement and other benefit obligations		250		152
Deferred income taxes		928		928
Derivative instruments		0		0
Off-market Lease, Unfavorable		0		0
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		0		0
Other non-current liabilities		74		47
Total non-current liabilities		8,712		9,312
Total Liabilities		6,925		8,890
Redeemable noncontrolling interest in subsidiaries		0		302
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		0		0
Stockholders' Equity		3,689		3,156
Total Liabilities and Stockholders' Equity		$ 10,614		$ 12,348
Convertible Preferred Stock [Member]
Condensed Financial Statements
Preferred Stock, Dividend Rate Amended, Percentage		2.822%		2.822%		2.822%
Consolidation, Eliminations [Member]
Current Assets
Cash and cash equivalents		$ 0	[1],[2]	$ 0	[2],[3],[4]	$ 0	[4],[5]		$ 0	[5]
Funds deposited by counterparties		0	[1]	0	[3]
Restricted cash		0	[1]	0	[3]
Accounts receivable - trade, net		0	[1]	0	[3]
Due from Affiliate, Current		(262)	[1]	(1,222)	[3]
Inventory		0	[1]	0	[3]
Derivative instruments		(205)	[1]	(158)	[3]
Derivative, Collateral, Right to Reclaim Cash		0	[1]	0	[3]
Disposal Group, Including Discontinued Operation, Other Assets, Current		0	[1]	0	[3]
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		0	[1]	0	[3]
Total current assets		(467)	[1]	(1,380)	[3]
Net Property, Plant and Equipment		(27)	[1]	(27)	[3]
Other Assets
Investment in subsidiaries		(12,938)	[1]	(14,125)	[3]
Equity investments in affiliates		0	[1]	(102)	[3]
Notes receivable, less current portion		76	[1]	0	[3]
Goodwill		0	[1]	0	[3]
Intangible assets, net		(3)	[1]	(6)	[3]
Nuclear decommissioning trust fund		0	[1]	0	[3]
Deferred income taxes		0	[1]	0	[3]
Derivative instruments		(50)	[1]	(32)	[3]
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		0	[1]	0	[3]
Other non-current assets		0	[1]	0	[3]
Total other assets		(12,915)	[1]	(14,265)	[3]
Total assets		(13,409)	[1]	(15,672)	[3]
Current Liabilities
Current portion of long-term debt and capital leases		76	[1]	0	[3]
Accounts payable		0	[1]	0	[3]
Accounts payable - affiliate		(262)	[1]	(1,222)	[3]
Derivative instruments		(205)	[1]	(158)	[3]
Cash collateral received in support of energy risk management activities		0	[1]	0	[3]
Accrued interest expense		0	[1]	(1)	[3]
Other accrued expenses		0	[1]	0	[3]
Disposal Group, Including Discontinued Operation, Liabilities, Current	[3]			0
Other current liabilities		0	[1]	0	[3]
Total current liabilities		(391)	[1]	(1,381)	[3]
Other Liabilities
Long-term debt and capital leases		0	[1]	0	[3]
Nuclear decommissioning reserve		0	[1]	0	[3]
Nuclear decommissioning trust liability		0	[1]	0	[3]
Postretirement and other benefit obligations		0	[1]	0	[3]
Deferred income taxes		0	[1]	0	[3]
Derivative instruments		(50)	[1]	(32)	[3]
Off-market Lease, Unfavorable		0	[1]	0	[3]
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		0	[1]	0	[3]
Other non-current liabilities		0	[1]	0	[3]
Total non-current liabilities		(50)	[1]	(32)	[3]
Total Liabilities		(441)	[1]	(1,413)	[3]
Redeemable noncontrolling interest in subsidiaries		0	[1]	0	[3]
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		0	[1]	0	[3]
Stockholders' Equity		(12,968)	[1]	(14,259)	[3]
Total Liabilities and Stockholders' Equity		$ (13,409)	[1]	$ (15,672)	[3]
[1]	All significant intercompany transactions have been eliminated in consolidation.
[2]	All significant intercompany transactions have been eliminated in consolidation.
[3]	All significant intercompany transactions have been eliminated in consolidation.
[4]	All significant intercompany transactions have been eliminated in consolidation.
[5]	All significant intercompany transactions have been eliminated in consolidation.

Condensed Consolidating Fina139

Condensed Consolidating Financial Information (Statements of Cash Flows) (Details 5) - USD ($) $ in Millions		3 Months Ended												12 Months Ended
		Dec. 31, 2016		Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Cash Flows from Operating Activities
Net (Loss)/Income		$ (1,055)		$ 393	$ (276)	$ 47		$ (6,358)		$ 67	$ (9)	$ (136)		$ (891)		$ (6,436)		$ 132
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														81		73		87
Equity in earnings of unconsolidated affiliates														(27)		(36)		(38)
Depreciation and amortization														1,367		1,566		1,523
Provision for bad debts														48		64		64
Amortization of nuclear fuel														49		45		46
Amortization of Financing Costs and Discounts														3		(11)		(12)
Gains Losses on Extinguishment of Debt, Non Cash Portion														21		(75)		25
Amortization of Intangibles and Out of Market Contracts														91		81		64
Share-based Compensation														10		41		42
Net (gain)/loss on sale of assets and equity method investments														(224)		14		(4)
Changes in nuclear decommissioning trust liability														(41)		2		(19)
Increase (Decrease) in Other Operating Assets and Liabilities, Net														92		149		217
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments														0		(21)		0
Impairment Charges and Asset Write Downs														1,186		5,086		97
Changes in Derivatives														23		233		(61)
Changes in Collateral Deposits Supporting Energy Risk Management Activities														365		(381)		146
Gain on sale of emissions allowances														47		0		0
Increase (Decrease) in Income Taxes														(43)		1,326		(154)
Other assets and liabilities														(75)		(258)		(466)
Net Cash Provided by Operating Activities														2,072		1,309		1,510
Cash Flows from Investing Activities
Payments to Acquire Business Two, Net of Cash Acquired														0		0
Intercompany Dividend Proceeds - Investing														0		0
Acquisition of businesses, net of cash acquired														(209)		(31)		(2,936)
Capital expenditures														(1,244)		(1,283)		(909)
(Increase)/decrease in restricted cash, net														(29)		8		57
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														(3)		35		(206)
Increase (Decrease) in Notes Receivables														17		18		25
Proceeds from Renewable Energy Grants														(36)		(82)		(916)
Purchases of emission allowances, net of proceeds														(1)		41		(16)
Payments to Acquire Available-for-sale Securities														(551)		(629)		(619)
Proceeds from sales of nuclear decommissioning trust fund securities														510		631		600
Proceeds/(purchases) from sale of assets, net														636		27		203
(Investments in)/proceeds from sales of unconsolidated affiliates, net														34		395		103
Other														48		11		85
Net Cash Used by Investing Activities														(824)		(1,485)		(2,903)
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														0		0		0
Payments to Acquire Business Three, Net of Cash Acquired														0		0
Intercompany Dividend Proceeds - Financing														0		0
Payments of Ordinary Dividends, Common Stock														(76)		(201)		(196)
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														151		196		9
Payments for Repurchase of Redeemable Preferred Stock					$ (226)									(226)		0		0
Proceeds from (Payments to) Noncontrolling Interests														(156)		47		189
Proceeds from sale of noncontrolling interests in subsidiaries														0		600		630
Payments for treasury stock														0		(437)		(39)
Proceeds from issuance of common stock, net of issuance costs														(1)		(1)		(21)
Proceeds from issuance of long-term debt														(5,527)		(1,004)		(4,563)
Payments of debt issuance and hedging costs														(89)		(21)		(67)
Payments for short and long-term debt														5,913		1,599		3,827
Proceeds from (Payments for) Other Financing Activities														(13)		(22)		(18)
Net Cash Provided by Financing Activities														(794)		(432)		1,265
Effect of exchange rate changes on cash and cash equivalents														1		10		(10)
Net Increase/(Decrease) in Cash and Cash Equivalents														455		(598)		(138)
Cash and Cash Equivalents at Beginning of Period						1,518						2,116		1,518		2,116		2,254
Cash and Cash Equivalents at End of Period		1,973						1,518						1,973		1,518		2,116
Guarantor Subsidiaries
Cash Flows from Operating Activities
Net (Loss)/Income														596		(2,586)		924
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														0		3		0
Equity in earnings of unconsolidated affiliates														(5)		(8)		(13)
Depreciation and amortization														565		787		801
Provision for bad debts														41		58		64
Amortization of nuclear fuel														49		45		46
Amortization of Financing Costs and Discounts														0		0		0
Gains Losses on Extinguishment of Debt, Non Cash Portion														0		0		0
Amortization of Intangibles and Out of Market Contracts														39		52		65
Share-based Compensation														0		0		0
Net (gain)/loss on sale of assets and equity method investments														0		0		0
Changes in nuclear decommissioning trust liability														(41)		2		(19)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments																0
Impairment Charges and Asset Write Downs														378		4,655		0
Changes in Derivatives														(77)		264		(149)
Changes in Collateral Deposits Supporting Energy Risk Management Activities														437		(360)		101
Gain on sale of emissions allowances														47
Increase (Decrease) in Income Taxes														(1)		(1,092)		242
Other assets and liabilities														(1,806)		(8,744)		686
Net Cash Provided by Operating Activities														304		(6,928)		2,786
Cash Flows from Investing Activities
Payments to Acquire Business Two, Net of Cash Acquired														0		0
Intercompany Dividend Proceeds - Investing														0		0
Acquisition of businesses, net of cash acquired														0		0		0
Capital expenditures														(180)		(316)		(252)
(Increase)/decrease in restricted cash, net														(4)		(1)		0
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														0		0		0
Increase (Decrease) in Notes Receivables														0		0		0
Proceeds from Renewable Energy Grants														0		0		0
Purchases of emission allowances, net of proceeds														(1)		41		(16)
Payments to Acquire Available-for-sale Securities														(551)		(629)		(619)
Proceeds from sales of nuclear decommissioning trust fund securities														510		631		600
Proceeds/(purchases) from sale of assets, net														0		0		0
(Investments in)/proceeds from sales of unconsolidated affiliates, net														(3)		(1)		0
Other														27		0		0
Net Cash Used by Investing Activities														(196)		(273)		(287)
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														52		(7,183)		2,523
Payments to Acquire Business Three, Net of Cash Acquired														0		0
Intercompany Dividend Proceeds - Financing														(52)		0
Payments of Ordinary Dividends, Common Stock														0		0		0
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														0		0		0
Payments for Repurchase of Redeemable Preferred Stock														0
Proceeds from (Payments to) Noncontrolling Interests														0		0		0
Proceeds from sale of noncontrolling interests in subsidiaries																0		0
Payments for treasury stock																0		0
Proceeds from issuance of common stock, net of issuance costs														0		0		0
Proceeds from issuance of long-term debt														0		0		0
Payments of debt issuance and hedging costs														0		0		0
Payments for short and long-term debt														1		0		0
Proceeds from (Payments for) Other Financing Activities														(3)		0		(14)
Net Cash Provided by Financing Activities														(108)		7,183		(2,537)
Effect of exchange rate changes on cash and cash equivalents														0		0		0
Net Increase/(Decrease) in Cash and Cash Equivalents														0		(18)		(38)
Cash and Cash Equivalents at Beginning of Period						0						18		0		18		56
Cash and Cash Equivalents at End of Period		0						0						0		0		18
Non-Guarantor Subsidiaries
Cash Flows from Operating Activities
Net (Loss)/Income														(592)		(351)		426
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														89		91		87
Equity in earnings of unconsolidated affiliates														(37)		(37)		(33)
Depreciation and amortization														776		759		706
Provision for bad debts														7		3		0
Amortization of nuclear fuel														0		0		0
Amortization of Financing Costs and Discounts														(18)		(37)		(40)
Gains Losses on Extinguishment of Debt, Non Cash Portion														4		(56)		8
Amortization of Intangibles and Out of Market Contracts														52		29		(1)
Share-based Compensation														0		0		0
Net (gain)/loss on sale of assets and equity method investments														(294)		0		(4)
Changes in nuclear decommissioning trust liability														0		0		0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments																(21)
Impairment Charges and Asset Write Downs														808		400		119
Changes in Derivatives														136		(31)		88
Changes in Collateral Deposits Supporting Energy Risk Management Activities														(72)		(21)		45
Gain on sale of emissions allowances														0
Increase (Decrease) in Income Taxes														18		(237)		(115)
Other assets and liabilities														364		(847)		(958)
Net Cash Provided by Operating Activities														1,241		(356)		328
Cash Flows from Investing Activities
Payments to Acquire Business Two, Net of Cash Acquired														(77)		(698)
Intercompany Dividend Proceeds - Investing														0		0
Acquisition of businesses, net of cash acquired														(209)		(31)		(25)
Capital expenditures														(1,016)		(908)		(619)
(Increase)/decrease in restricted cash, net														(25)		9		57
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														(3)		34		(209)
Increase (Decrease) in Notes Receivables														17		18		25
Proceeds from Renewable Energy Grants														(36)		(82)		(916)
Purchases of emission allowances, net of proceeds														0		0		0
Payments to Acquire Available-for-sale Securities														0		0		0
Proceeds from sales of nuclear decommissioning trust fund securities														0		0		0
Proceeds/(purchases) from sale of assets, net														619		1		0
(Investments in)/proceeds from sales of unconsolidated affiliates, net														37		357		25
Other														13		11		85
Net Cash Used by Investing Activities														(682)		(1,839)		205
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														49		(1,258)		685
Payments to Acquire Business Three, Net of Cash Acquired														0		0
Intercompany Dividend Proceeds - Financing														40		(33)
Payments of Ordinary Dividends, Common Stock														0		0		0
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														151		196		9
Payments for Repurchase of Redeemable Preferred Stock														0
Proceeds from (Payments to) Noncontrolling Interests														(156)		47		189
Proceeds from sale of noncontrolling interests in subsidiaries																600		630
Payments for treasury stock																0		0
Proceeds from issuance of common stock, net of issuance costs														0		0		0
Proceeds from issuance of long-term debt														(1,387)		(953)		(1,182)
Payments of debt issuance and hedging costs														(29)		(21)		(39)
Payments for short and long-term debt														988		1,353		1,160
Proceeds from (Payments for) Other Financing Activities														(10)		(22)		(4)
Net Cash Provided by Financing Activities														265		1,555		62
Effect of exchange rate changes on cash and cash equivalents														1		10		(10)
Net Increase/(Decrease) in Cash and Cash Equivalents														825		(630)		585
Cash and Cash Equivalents at Beginning of Period						825						1,455		825		1,455		870
Cash and Cash Equivalents at End of Period		1,650						825						1,650		825		1,455
NRG Energy, Inc.
Cash Flows from Operating Activities
Net (Loss)/Income														(718)		(6,351)		149
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														0		0		0
Equity in earnings of unconsolidated affiliates														5		0		0
Depreciation and amortization														26		20		16
Provision for bad debts														0		3		0
Amortization of nuclear fuel														0		0		0
Amortization of Financing Costs and Discounts														21		26		28
Gains Losses on Extinguishment of Debt, Non Cash Portion														17		(19)		17
Amortization of Intangibles and Out of Market Contracts														0		0		0
Share-based Compensation														10		41		42
Net (gain)/loss on sale of assets and equity method investments														70		14		0
Changes in nuclear decommissioning trust liability														0		0		0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments																0
Impairment Charges and Asset Write Downs														0		31		0
Changes in Derivatives														(36)		0		0
Changes in Collateral Deposits Supporting Energy Risk Management Activities														0		0		0
Gain on sale of emissions allowances														0
Increase (Decrease) in Income Taxes														(60)		2,655		(281)
Other assets and liabilities														1,192		12,173		(1,575)
Net Cash Provided by Operating Activities														527		8,593		(1,604)
Cash Flows from Investing Activities
Payments to Acquire Business Two, Net of Cash Acquired														0		0
Intercompany Dividend Proceeds - Investing														(12)		(33)
Acquisition of businesses, net of cash acquired														0		0		(2,911)
Capital expenditures														(48)		(59)		(38)
(Increase)/decrease in restricted cash, net														0		0		0
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														0		1		3
Increase (Decrease) in Notes Receivables														0		0		0
Proceeds from Renewable Energy Grants														0		0		0
Purchases of emission allowances, net of proceeds														0		0		0
Payments to Acquire Available-for-sale Securities														0		0		0
Proceeds from sales of nuclear decommissioning trust fund securities														0		0		0
Proceeds/(purchases) from sale of assets, net														17		26		203
(Investments in)/proceeds from sales of unconsolidated affiliates, net														0		39		78
Other														8		0		0
Net Cash Used by Investing Activities														70		32		(2,761)
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														(101)		8,441		(3,208)
Payments to Acquire Business Three, Net of Cash Acquired														77		698
Intercompany Dividend Proceeds - Financing														0		0
Payments of Ordinary Dividends, Common Stock														(76)		(201)		(196)
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														0		0		0
Payments for Repurchase of Redeemable Preferred Stock														(226)
Proceeds from (Payments to) Noncontrolling Interests														0		0		0
Proceeds from sale of noncontrolling interests in subsidiaries																0		0
Payments for treasury stock																(437)		(39)
Proceeds from issuance of common stock, net of issuance costs														(1)		(1)		(21)
Proceeds from issuance of long-term debt														(4,140)		(51)		(3,381)
Payments of debt issuance and hedging costs														(60)		0		(28)
Payments for short and long-term debt														4,924		246		2,667
Proceeds from (Payments for) Other Financing Activities														0		0		0
Net Cash Provided by Financing Activities														(967)		(8,575)		3,680
Effect of exchange rate changes on cash and cash equivalents														0		0		0
Net Increase/(Decrease) in Cash and Cash Equivalents														(370)		50		(685)
Cash and Cash Equivalents at Beginning of Period						693						643		693		643		1,328
Cash and Cash Equivalents at End of Period		323						693						323		693		643
NRG Yield [Member]
Cash Flows from Financing Activities
Proceeds from issuance of common stock, net of issuance costs																		0
Consolidation, Eliminations [Member]
Cash Flows from Operating Activities
Net (Loss)/Income														(177)	[1],[2]	2,852	[3],[4]	(1,367)	[5],[6]
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														(8)	[2]	(21)	[4]	0	[6]
Equity in earnings of unconsolidated affiliates														10	[1],[2]	9	[3],[4]	8	[5],[6]
Depreciation and amortization														0	[1],[2]	0	[3],[4]	0	[5],[6]
Provision for bad debts														0	[2]	0	[4]	0	[6]
Amortization of nuclear fuel														0	[2]	0	[4]	0	[6]
Amortization of Financing Costs and Discounts														0	[2]	0	[4]	0	[6]
Gains Losses on Extinguishment of Debt, Non Cash Portion														0	[2]	0	[4]	0	[6]
Amortization of Intangibles and Out of Market Contracts														0	[2]	0	[4]	0	[6]
Share-based Compensation														0	[2]	0	[4]	0	[6]
Net (gain)/loss on sale of assets and equity method investments														0	[2]	0	[4]	0	[6]
Changes in nuclear decommissioning trust liability														0	[2]	0	[4]	0	[6]
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	[3],[4]															0
Impairment Charges and Asset Write Downs														0	[2]	0	[4]	(22)	[6]
Changes in Derivatives														0	[2]	0	[4]	0	[6]
Changes in Collateral Deposits Supporting Energy Risk Management Activities														0	[2]	0	[4]	0	[6]
Gain on sale of emissions allowances	[2]													0
Increase (Decrease) in Income Taxes														0	[2]	0	[4]	0	[6]
Other assets and liabilities														175	[2]	(2,840)	[4]	1,381	[6]
Net Cash Provided by Operating Activities														0	[2]	0	[4]	0	[6]
Cash Flows from Investing Activities
Payments to Acquire Business Two, Net of Cash Acquired														77	[2]	698	[4]
Intercompany Dividend Proceeds - Investing														12	[2]	33	[4]
Acquisition of businesses, net of cash acquired														0	[2]	0	[4]	0	[6]
Capital expenditures														0	[2]	0	[4]	0	[6]
(Increase)/decrease in restricted cash, net														0	[2]	0	[4]	0	[6]
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														0	[2]	0	[4]	0	[6]
Increase (Decrease) in Notes Receivables														0	[2]	0	[4]	0	[6]
Proceeds from Renewable Energy Grants														0	[2]	0	[4]	0	[6]
Purchases of emission allowances, net of proceeds														0	[2]	0	[4]	0	[6]
Payments to Acquire Available-for-sale Securities														0	[2]	0	[4]	0	[6]
Proceeds from sales of nuclear decommissioning trust fund securities														0	[2]	0	[4]	0	[6]
Proceeds/(purchases) from sale of assets, net														0	[2]	0	[4]	0	[6]
(Investments in)/proceeds from sales of unconsolidated affiliates, net														0	[2]	0	[4]	0	[6]
Other														0	[2]	0	[4]	0	[6]
Net Cash Used by Investing Activities														(16)	[2]	595	[4]	(60)	[6]
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														0	[2]	0	[4]		[6]
Payments to Acquire Business Three, Net of Cash Acquired														(77)	[2]	(698)	[4]
Intercompany Dividend Proceeds - Financing														12	[2]	33	[4]
Payments of Ordinary Dividends, Common Stock														0	[2]	0	[4]	0	[6]
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														0	[2]	0	[4]	0	[6]
Payments for Repurchase of Redeemable Preferred Stock	[2]													0
Proceeds from (Payments to) Noncontrolling Interests														0	[2]	0	[4]	0	[6]
Proceeds from sale of noncontrolling interests in subsidiaries																0	[4]	0	[6]
Payments for treasury stock																0	[4]	0	[6]
Proceeds from issuance of common stock, net of issuance costs														0	[2]	0	[4]	0	[6]
Proceeds from issuance of long-term debt														0	[2]	0	[4]	0	[6]
Payments of debt issuance and hedging costs														0	[2]	0	[4]	0	[6]
Payments for short and long-term debt														0	[2]	0	[4]	0	[6]
Proceeds from (Payments for) Other Financing Activities														0	[2]	0	[4]	0	[6]
Net Cash Provided by Financing Activities														16	[2]	(595)	[4]	60	[6]
Effect of exchange rate changes on cash and cash equivalents														0	[2]	0	[4]	0	[6]
Net Increase/(Decrease) in Cash and Cash Equivalents														0	[2]	0	[4]	0	[6]
Cash and Cash Equivalents at Beginning of Period						$ 0	[2],[4],[7]					$ 0	[4],[6]	0	[2],[4],[7]	0	[4],[6]	0	[6]
Cash and Cash Equivalents at End of Period		$ 0	[2],[8]					$ 0	[2],[4],[7]					0	[2],[8]	0	[2],[4],[7]	0	[4],[6]
NRG Yield, Inc. [Member]
Cash Flows from Investing Activities
Intercompany Dividend Proceeds - Investing														0		0		0
Cash Flows from Financing Activities
Intercompany Dividend Proceeds - Financing														0		0		0
NRG Yield, Inc. [Member] | Guarantor Subsidiaries
Cash Flows from Investing Activities
Intercompany Dividend Proceeds - Investing														0		0		0
Cash Flows from Financing Activities
Intercompany Dividend Proceeds - Financing														0		0		0
NRG Yield, Inc. [Member] | Non-Guarantor Subsidiaries
Cash Flows from Investing Activities
Intercompany Dividend Proceeds - Investing														0		0		0
Cash Flows from Financing Activities
Intercompany Dividend Proceeds - Financing														(81)		(70)		(60)
NRG Yield, Inc. [Member] | NRG Energy, Inc.
Cash Flows from Investing Activities
Intercompany Dividend Proceeds - Investing														(81)		(70)		60
Cash Flows from Financing Activities
Intercompany Dividend Proceeds - Financing														0		0		0
NRG Yield, Inc. [Member] | Consolidation, Eliminations [Member]
Cash Flows from Investing Activities
Intercompany Dividend Proceeds - Investing														81	[2]	70	[4]	(60)	[6]
Cash Flows from Financing Activities
Intercompany Dividend Proceeds - Financing														$ 81	[2]	$ 70	[4]	$ 60	[6]
[1]	All significant intercompany transactions have been eliminated in consolidation.
[2]	All significant intercompany transactions have been eliminated in consolidation.
[3]	All significant intercompany transactions have been eliminated in consolidation.
[4]	All significant intercompany transactions have been eliminated in consolidation.
[5]	All significant intercompany transactions have been eliminated in consolidation.
[6]	All significant intercompany transactions have been eliminated in consolidation.
[7]	All significant intercompany transactions have been eliminated in consolidation.
[8]	All significant intercompany transactions have been eliminated in consolidation.

VALUATION AND QUALIFYING ACC140

VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in Valuation and Qualifying Accounts
Balance at Beginning of Period		$ 5
Balance at End of Period		11	$ 5
Allowance for doubtful accounts, deducted from accounts receivable
Changes in Valuation and Qualifying Accounts
Balance at Beginning of Period		21	23	$ 40
Charged to Costs and Expenses		48	62	64
Charged to Other Accounts		0	0	0
Deductions	[1]	39	64	81
Balance at End of Period		30	21	23
Income tax valuation allowance, deducted from deferred tax assets
Changes in Valuation and Qualifying Accounts
Balance at Beginning of Period		3,575	265	291
Charged to Costs and Expenses		306	3,039	0
Charged to Other Accounts		235	271	(10)
Deductions		0	0	16
Balance at End of Period		$ 4,116	$ 3,575	$ 265
[1]	Represents principally net amounts charged as uncollectible.