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Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	NRG ENERGY, INC.
Entity Central Index Key	0001013871
Document Type	10-K
Document Period End Date	Dec. 31, 2017
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			$ 4,880,501,096
Entity Common Stock, Shares Outstanding		317,637,917
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Revenues
Total operating revenues	$ 10,629	$ 10,512	$ 12,328
Operating Costs and Expenses
Cost of operations	7,536	7,301	9,000
Depreciation and amortization	1,056	1,172	1,351
Impairment losses	1,709	702	4,860
Selling, general and administrative	907	1,095	1,228
Reorganization costs	44	0	0
Development costs	67	89	154
Total operating costs and expenses	11,319	10,359	16,593
Other income - affiliate	87	193	193
Gain/(loss) on sale of assets	16	(80)	0
Gain on postretirement benefits curtailment	0	0	21
Operating (Loss)/Income	(587)	266	(4,051)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	31	27	36
Impairment losses on investments	(79)	(268)	(56)
Other income, net	38	34	26
Loss on sale of equity method investment	0	0	(14)
Net (loss)/gain on debt extinguishment	(53)	(142)	10
Interest expense	(890)	(895)	(937)
Total other expense	(953)	(1,244)	(935)
Loss from Continuing Operations Before Income Taxes	(1,540)	(978)	(4,986)
Income tax expense	8	5	1,345
Net Loss from Continuing Operations	(1,548)	(983)	(6,331)
(Loss)/income from discontinued operations, net of income tax	(789)	92	(105)
Net Loss	(2,337)	(891)	(6,436)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(184)	(117)	(54)
Net Loss Attributable to NRG Energy, Inc.	(2,153)	(774)	(6,382)
Dividends for preferred shares	0	5	20
Gain on redemption of preferred shares	0	(78)	0
Loss Available for Common Stockholders	$ (2,153)	$ (701)	$ (6,402)
Loss Per Share Attributable to NRG Energy, Inc. Common Stockholders
Loss from continuing operations per weighted average common share — basic (in usd per share)	$ (4.30)	$ (2.51)	$ (19.14)
(Loss)/Income from discontinued operations per weighted average common share — basic and diluted (in usd per share)	(2.49)	0.29	(0.32)
Net Loss per Weighted Average Common Share — Basic and Diluted (in usd per share)	(6.79)	(2.22)	(19.46)
Dividends Per Common Share (in usd per share)	$ 0.12	$ 0.24	$ 0.58

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net Loss	$ (1,655)	$ 163	$ (642)	$ (203)	$ (1,055)	$ 393	$ (276)	$ 47	$ (2,337)	$ (891)	$ (6,436)
Other Comprehensive Income, net of tax
Unrealized gain/(loss) on derivatives, net of income tax expense of $1, $1, and $19									13	35	(15)
Foreign currency translation adjustments, net of income tax benefit of $(2), $0, and $0									12	(1)	(11)
Available-for-sale securities, net of income tax expense/(benefit) of $10, $0, and $(3)									(8)	1	17
Defined benefit plan, net of income tax (benefit)/expense of $(21), $0 and $69									46	3	10
Other comprehensive income									63	38	1
Comprehensive Loss									(2,274)	(853)	(6,435)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests									(179)	(117)	(73)
Comprehensive Loss Attributable to NRG Energy, Inc.									(2,095)	(736)	(6,362)
Dividends for preferred shares									0	5	20
Gain on redemption of preferred shares									0	(78)	0
Comprehensive Loss Available for Common Stockholders									$ (2,095)	$ (663)	$ (6,382)

Consolidated Statements of Comprehensive (Loss)/Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Unrealized gain/(loss) on derivatives, net of income tax expense of $1, $1, and $19	$ 1	$ 1	$ 19
Foreign currency translation adjustments, net of income tax benefit of $(2), $0, and $0	2	0	0
Available-for-sale securities, net of income tax expense/(benefit) of $10, $0, and $(3)	10	0	(3)
Defined benefit plan, net of income tax (benefit)/expense of $(21), $0 and $69	$ (21)	$ 0	$ 69

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 991	$ 938
Funds deposited by counterparties	37	2
Restricted cash	508	446
Accounts receivable — trade	1,079	1,058
Inventory	532	721
Derivative instruments	626	1,067
Cash collateral posted in support of energy risk management activities	171	150
Accounts receivable — affiliate	95	0
Current assets held-for-sale	115	9
Prepayments and other current assets	261	404
Current assets - discontinued operations	0	1,919
Total current assets	4,415	6,714
Property, plant and equipment, net	13,908	15,369
Other Assets
Equity investments in affiliates	1,038	1,120
Notes receivable, less current portion	2	16
Goodwill	539	662
Intangible assets, net	1,746	1,973
Nuclear decommissioning trust fund	692	610
Derivative instruments	172	181
Deferred income taxes	134	225
Non-current assets held-for-sale	43	10
Other non-current assets	629	841
Non-current assets - discontinued operations	0	2,961
Total other assets	4,995	8,599
Total Assets	23,318	30,682
Current Liabilities
Current portion of long-term debt and capital leases	688	516
Accounts payable	881	782
Accounts payable - affiliate	33	31
Derivative instruments	555	1,092
Cash collateral received in support of energy risk management activities	37	81
Accrued interest expense	156	180
Current liabilities - held for sale	72	0
Other accrued expenses and other current liabilities	734	810
Other accrued expenses and other current liabilities - affiliate	161	0
Current liabilities - discontinued operations	0	1,210
Total current liabilities	3,317	4,702
Other Liabilities
Long-term debt and capital leases	15,716	15,957
Nuclear decommissioning reserve	269	287
Nuclear decommissioning trust liability	415	339
Postretirement and other benefit obligations	458	510
Deferred income taxes	21	20
Derivative instruments	197	284
Out-of-market contracts, net	207	230
Non-current liabilities held-for-sale	8	11
Other non-current liabilities	664	666
Non-current liabilities - discontinued operations	0	3,184
Total non-current liabilities	17,955	21,488
Total Liabilities	21,272	26,190
Redeemable noncontrolling interest in subsidiaries	78	46
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 418,323,134 and 417,583,825 shares issued; and 316,743,089 and 315,443,011 shares outstanding at December 31, 2017 and 2016	4	4
Additional paid-in capital	8,376	8,358
Accumulated deficit	(6,268)	(3,787)
Treasury stock, at cost; 101,580,045 and 102,140,814 shares at December 31, 2017 and 2016	(2,386)	(2,399)
Accumulated other comprehensive loss	(72)	(135)
Noncontrolling interest	2,314	2,405
Total Stockholders' Equity	1,968	4,446
Total Liabilities and Stockholders' Equity	$ 23,318	$ 30,682

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500,000,000	500,000,000
Common stock, shares issued (in shares)	418,323,134	417,583,825
Common stock, shares outstanding (in shares)	316,743,089	315,443,011
Treasury stock, shares (in shares)	101,580,045	102,140,814

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows from Operating Activities
Net Loss	$ (2,337)	$ (891)	$ (6,436)
(Loss)/income from discontinued operations, net of income tax	(789)	92	(105)
Net Loss from Continuing Operations	(1,548)	(983)	(6,331)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distribution of unconsolidated affiliates	55	54	37
Depreciation and amortization	1,056	1,172	1,351
Provision for bad debts	68	48	64
Amortization of nuclear fuel	51	49	45
Amortization of financing costs and debt discount/premiums	60	55	47
Adjustment for debt extinguishment	53	142	(10)
Amortization of intangibles and out-of-market contracts	108	167	151
Amortization of unearned equity compensation	35	10	39
Net (gain)/loss on sale of assets and equity method investments	(34)	70	14
Gain on post retirement benefits curtailment	0	0	(21)
Impairment losses	1,788	972	4,916
Changes in derivative instruments	(171)	32	235
Changes in deferred income taxes and liability for uncertain tax benefits	91	(43)	1,326
Changes in collateral deposits in support of risk management activities	(80)	398	(334)
Proceeds from sale of emission allowances	25	34	(24)
Changes in nuclear decommissioning trust liability	11	41	(2)
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects:
Accounts receivable - trade	(99)	(7)	113
Inventory	143	71	(59)
Prepayments and other current assets	12	(44)	(21)
Accounts payable	77	(39)	(180)
Accrued expenses and other current liabilities	(60)	(35)	(29)
Other assets and liabilities	(216)	43	(40)
Cash provided by continuing operations	1,425	2,207	1,287
Cash (used)/provided by discontinued operations	(38)	(119)	62
Net Cash Provided by Operating Activities	1,387	2,088	1,349
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(41)	(209)	(31)
Capital expenditures	(1,111)	(976)	(1,029)
Net cash proceeds from notes receivable	17	17	18
Proceeds from renewable energy grants	8	36	82
Proceeds from/(purchases) of emission allowances, net of purchases	66	(1)	41
Investments in nuclear decommissioning trust fund securities	(512)	(551)	(629)
Proceeds from sales of nuclear decommissioning trust fund securities	501	510	631
Proceeds from sale of assets, net	87	73	27
Investments in unconsolidated affiliates	(40)	(23)	(395)
Other	12	35	16
Cash used by continuing operations	(1,013)	(1,089)	(1,269)
Cash (used)/provided by discontinued operations	(53)	297	(259)
Net Cash Used by Investing Activities	(1,066)	(792)	(1,528)
Cash Flows from Financing Activities
Payments of dividends to preferred and common stockholders	(38)	(76)	(201)
Net receipts from settlement of acquired derivatives that include financing elements	2	6	14
Payments for treasury stock	0	0	(437)
Payments for preferred shares	0	(226)	0
Payments for debt extinguishment costs	(42)	(121)	0
Distributions to, net of contributions from, noncontrolling interests in subsidiaries	95	(156)	47
Proceeds from sale of noncontrolling interests in subsidiaries	0	0	600
(Payments)/Proceeds from issuance of common stock	(2)	1	1
Proceeds from issuance of long-term debt	2,270	5,527	1,004
Payments of debt issuance and hedging costs	(63)	(89)	(21)
Payments for short and long-term debt	(2,348)	(5,908)	(1,362)
Receivable from affiliate	(125)	0	0
Other	(10)	(13)	(22)
Cash used by continuing operations	(261)	(1,055)	(377)
Cash (used)/provided by discontinued operations	(224)	140	(55)
Net Cash Provided/(Used) by Financing Activities	(485)	(915)	(432)
Effect of exchange rate changes on cash and cash equivalents	(1)	1	10
Change in Cash from discontinued operations	(315)	318	(252)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	150	64	(349)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,386	1,322	1,671
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$ 1,536	$ 1,386	$ 1,322

CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY - USD ($) $ in Millions	Total	Common Stock	Additional Paid-In Capital	Retained Earnings/ (Accumu-lated Deficit)	Treasury Stock	Accumulated Other Comprehensive Income/(Loss)	Noncon- trolling Interest	NRG Yield	NRG Yield, Inc.	NRG Yield, Inc. Noncon- trolling Interest
Balance at Dec. 31, 2014	$ 11,676	$ 4	$ 8,327	$ 3,588	$ (1,983)	$ (174)	$ 1,914
Increase (Decrease) in Stockholders' Equity
Net loss	(6,419)			(6,382)			(37)
Other comprehensive income (loss)	1					1
Other comprehensive income (loss) portion attributable to noncontrolling interest							(4)
Other comprehensive income (loss), including OCI for NCI	(3)
Sale of assets to NRG Yield, Inc.			(56)				83	$ 27
ESPP share purchases	6		(1)		7
Equity-based compensation	24		26	(2)
Purchase of treasury stock	(437)				(437)
Common stock dividends	(191)			(191)
Preferred stock dividends	(20)			(20)
Distributions to redeemable noncontrolling interest	(159)						(159)
Gain on redemption of preferred shares	0
Contributions from noncontrolling interests	234						234
Acquisition of noncontrolling interests by NRG Yield, Inc.							74	74
Impact of NRG Yield, Inc. public offering	599						599
Equity component of NRG Yield, Inc. convertible notes	23						23
Balance at Dec. 31, 2015	5,434	4	8,296	(3,007)	(2,413)	(173)	2,727
Increase (Decrease) in Stockholders' Equity
Net loss	(853)			(774)			(79)
Other comprehensive income (loss)	38					38
Other comprehensive income (loss), including OCI for NCI	38
Sale of assets to NRG Yield, Inc.			59				(16)	43
ESPP share purchases	6		(2)	(6)	14
Equity-based compensation	6		5	1
Common stock dividends	(74)			(74)
Preferred stock dividends	(5)			(5)
Distributions to redeemable noncontrolling interest	(158)						(158)		$ (92)	$ (92)
Gain on redemption of preferred shares	78			78
Contributions from noncontrolling interests	30						30
Redemption of noncontrolling interests	(7)						(7)
Balance at Dec. 31, 2016	4,446	4	8,358	(3,787)	(2,399)	(135)	2,405
Increase (Decrease) in Stockholders' Equity
Net loss	(2,251)			(2,153)			(98)
Other comprehensive income (loss)	63					51
Other comprehensive income (loss), including OCI for NCI	51
Sale of assets to NRG Yield, Inc.			(25)				20	$ (5)
ESPP share purchases	6		(3)	(4)	13
Equity-based compensation	29		29
Common stock dividends	(38)			(38)
Distributions to redeemable noncontrolling interest	(65)						(65)		$ (108)	$ (108)
Gain on redemption of preferred shares	0
Contributions from noncontrolling interests	160						160
Cumulative effect adjustment	(257)		17	(286)		12
Balance at Dec. 31, 2017	$ 1,968	$ 4	$ 8,376	$ (6,268)	$ (2,386)	$ (72)	$ 2,314

Nature of Business	12 Months Ended
Nature of Business	Dec. 31, 2017
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 a 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 30,000 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 Chapter 11 Cases On June 14, 2017, or the Petition Date, GenOn, along with GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries, or collectively the GenOn Entities, filed voluntary petitions for relief under Chapter 11, or the Chapter 11 Cases, of the U.S. Bankruptcy Code, or the Bankruptcy Code, in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division, or the Bankruptcy Court. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, REMA and certain other subsidiaries, did not file for relief under Chapter 11. As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries were deconsolidated from NRG’s consolidated financial statements. NRG recorded its investment in GenOn under the cost method with an estimated fair value of zero. NRG determined that this disposal of GenOn and its subsidiaries is a discontinued operation; and, accordingly, the financial information for all historical periods has been recast to reflect GenOn as a discontinued operation. In connection with the disposal, NRG recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017. See Note 3, Discontinued Operations, Acquisitions and Dispositions, for more information. Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization. There is no assurance that the GenOn Entities' plan will be successfully implemented. The principal terms of the Restructuring Support Agreement and further information regarding the Chapter 11 Cases are described further in Note 3, Discontinued Operations, Acquisitions and Dispositions. Transformation Plan On July 12, 2017, NRG announced its Transformation Plan designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the following targets: Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales. Portfolio optimization — Targeting up to $3.2 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform. Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales, the Company expects $5.3 billion in excess cash to be available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio. The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The Company expects to realize (i) $370 million of working capital improvements through 2020 and (ii) approximately $290 million, one-time costs to achieve. 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, 2017:

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

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, which includes generation, international and BETM; Retail, which includes Mass customers, and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. On June 14, 2017, as described in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG deconsolidated GenOn for financial reporting purposes. The financial information for all historical periods has been recast to reflect the presentation of GenOn as discontinued operations within the corporate 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. As of December 31, 2016, $79 million of the cash collateral received was from GenOn, previously a consolidated subsidiary, and is included in cash collateral received in current liabilities as a result of deconsolidating GenOn, with the offset included in cash and cash equivalents.

Restricted Cash

The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by counterparties reported within the consolidated balance sheet that sum to the total of the same such amounts shown in the statement of cash flows.



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Cash and cash equivalents	$	991	$	938	$	853
Funds deposited by counterparties	37		2		55
Restricted cash	508		446		414
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,536	$	1,386	$	1,322

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, 2017, approximately $51 million is designated for current debt service payments, $65 million is designated to fund operating expenses, and $57 million is designated to fund distributions, with the remaining $335 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, 2017 and 2016, the allowance for doubtful accounts was $28 million and $29 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, Discontinued Operations, 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, 2017, 2016, and 2015, was $34 million, $30 million, and $25 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, 2017 and 2016, the Company had accumulated amortization related to its intangible assets of $1.8 billion and $1.7 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.

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. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. If it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, there is no goodwill impairment.

In the absence of sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing the fair value to its book value. If the fair value of the reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, the Company recognizes an impairment loss equal to the difference between book value and fair value.

For further discussion of goodwill and goodwill impairment losses recognized during 2017 and 2016, 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, including the potential impact of the Tax Cuts and Jobs Act legislation, or the Tax Act, 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 $187 million, $154 million and $165 million for the years ended December 31, 2017, 2016, and 2015, 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 $376 million, $321 million and $307 million as of December 31, 2017, 2016, and 2015, 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, 2017, 2016, and 2015 was $879 million, $912 million, and $753 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, 2017, 2016, and 2015, the Company's revenues and cost of operations included gross receipts taxes of $92 million, $101 million, and $110 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 ($107 million, $90 million and $85 million as of December 31, 2017, 2016, and 2015, 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 cash flow hedges, if elected for hedge accounting, are 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, 2017, 2016, and 2015, amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2017, 2016, and 2015 were $(2) million, $(11) million and $(10) 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 certain amounts within noncontrolling interest, included in stockholders' equity, represent 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.

Redeemable Noncontrolling Interest

To the extent that the third-party has the right to redeem their interests for cash or other assets, the Company has included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet. The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2017, 2016, and 2015.



	(In millions)
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	33
Non-cash adjustments to redeemable noncontrolling interest	23
Comprehensive loss attributable to redeemable noncontrolling interest	(38		)
Balance as of December 31, 2016	46
Distributions to redeemable noncontrolling interest	(2		)
Contributions from redeemable noncontrolling interest	99
Non-cash adjustments to redeemable noncontrolling interest	7
Comprehensive loss attributable to redeemable noncontrolling interest	(72		)
Balance as of December 31, 2017	$	78

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

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, 2017, 2016, and 2015 were $184 million, $247 million, and $309 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, 2017, 2016, and 2015 were $42 million, $53 million, and $135 million, respectively.

Reorganization Costs

Reorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily reflect personnel costs related to cost savings initiatives. As of December 31, 2017, $44 million has been incurred.

Business Combinations

The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

In recording transactions and balances resulting from business operations, 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

Certain prior-year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.

Recent Accounting Developments - Guidance Adopted in 2017

ASU 2018-02 — In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, or ASU No. 2018-02. Prior to ASU No. 2018-02, GAAP required the remeasurement of deferred tax assets and liabilities as a result of a change in tax laws or rates to be presented in net income from continuing operations, even in situations in which the related income tax effects of items in accumulated other comprehensive income were originally recognized in other comprehensive income. As a result, such items, referred to as stranded tax effects, did not reflect the appropriate tax rate. Under ASU No. 2018-02, entities are permitted, but not required, to reclassify from accumulated other comprehensive income to retained earnings those stranded tax effects resulting from the Tax Act. ASU No. 2018-02 is effective for all entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Company adopted the new standard effective December 31, 2017. As a result of the adoption, the Company reclassified $13 million from accumulated other comprehensive loss to retained earnings in the consolidated balance sheet as of December 31, 2017.

ASU 2017-12 — In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, or ASU No. 2017-12. The amendments of ASU No. 2017-12 were issued to simplify the application of hedge accounting guidance and more closely align financial reporting for hedging relationships with economic results of an entity's risk management activities. The issues addressed by ASU No. 2017-12 include but are not limited to alignment of risk management activities and financial reporting, risk component hedging, accounting for the hedged item in fair value hedges of interest rate risk, recognition and presentation of the effects of hedging instruments, amounts excluded from the assessment of hedge effectiveness, and other simplifications of hedge accounting guidance. The Company adopted the guidance in ASU No. 2017-12 during the fourth quarter of 2017, with no material adjustments recorded to the consolidated results of operations, cash flows, and statement of financial position.

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 require an entity to include amounts generally described as restricted cash and restricted cash equivalents, including funds deposited by counterparties 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 will be applied retrospectively. The Company adopted the guidance in ASU No. 2016-18 during the second quarter of 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in a (decrease)/increase in cash flows from operations of $(53) million and $37 million and an increase/(decrease) in cash flows from investing of $32 million and $(43) million on the statement of cash flows for the years ended December 31, 2016 and 2015, respectively.

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. Previous GAAP prohibited 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 require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company adopted the guidance in ASU No. 2016-16 effective January 1, 2017. In connection with the adoption of the standard, the Company recorded a reduction to non-current assets of $267 million with a corresponding reduction to cumulative retained deficit as of December 31, 2017.

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 Company adopted the guidance in ASU No. 2016-15 effective January 1, 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cash flows from operations of $121 million and a decrease in cash flows from financing of $121 million on the statement of cash flows for the year ended December 31, 2016. There was no impact to the statement of cash flows for the year ended December 31, 2015, as a result of adoption.

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 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 Company adopted the guidance in ASU No. 2016-09 effective January 1, 2017, with no material adjustments recorded to the Company's consolidated financial statements.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2017-07 — In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07. Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and does not require entities to disclose the amount of net benefit cost that is included in the income statement. The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The Company adopted the amendments of ASU No. 2017-07 effective January 1, 2018. The adoption of ASU No. 2017-07 will not have a material impact on the Company's results of operations, cash flows, and statement of financial position.

ASU 2016-02 — In February 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 will adopt the standard effective January 1, 2019, and 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. While this review is still in process, NRG believes the adoption of Topic 842 will have a material impact on its financial statements. The Company is continuing to monitor potential changes to Topic 842 that have been proposed by the FASB and will assess any necessary changes to the implementation process as the guidance is updated.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or Topic 606, which was further amended through various updates issued by the FASB thereafter. The amendments of Topic 606 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 has also elected 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. The Company adopted the standard effective January 1, 2018. The adoption of Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method, will not have a material impact on the Company's financial statements. The adoption of Topic 606 also includes additional disclosure requirements beginning in the first quarter of 2018. Many of these disclosures are not substantially different than the Company's existing disclosures. Topic 606 requires disclosure of disaggregated revenue amounts, which the Company expects would include types of operating revenues by business.

Discontinued Operations, Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations, Acquisitions and Dispositions

Discontinued Operations

As described in Note 1, Nature of Business, on the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer controls GenOn as it is subject to the control of the Bankruptcy Court; and, accordingly, NRG no longer consolidates GenOn for financial reporting purposes.

By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn meets the criteria for discontinued operations, as this represents a strategic shift in the markets in which NRG operates. As such, all prior period results for GenOn have been reclassified as discontinued operations while NRG will record all ongoing results of GenOn as a cost method investment, which was valued at zero at the date of deconsolidation.

Summarized results of discontinued operations were as follows:



	Year ended December 31,
(In millions)	2017			2016
Operating revenues	$	646		$	1,862
Operating costs and expenses	(702		)	(1,896		)
Gain on sale of assets	—			294
Other expenses	(98		)	(168		)
(Loss)/Income from operations of discontinued components, before tax	(154		)	92
Income tax expense	9			11
(Loss)/Income from operations of discontinued components	(163		)	81
Interest income - affiliate	8			11
(Loss)/Income from operations of discontinued components, net of tax	(155		)	92
Pre-tax loss on deconsolidation	(208		)	—
Settlement consideration and services credit	(289		)	—
Pension and post-retirement liability assumption	(131		)	—
Other	(6		)	—
Loss on disposal of discontinued components, net of tax	(634		)	—
(Loss)/Income from discontinued operations, net of tax	$	(789	)	$	92

The following table summarizes the major classes of assets and liabilities classified as discontinued operations as of December 31, 2016. As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.



(In millions)	December 31, 2016
Cash and cash equivalents	$	1,034
Other current assets	885
Current assets - discontinued operations	1,919
Property, plant and equipment, net	2,543
Other non-current assets	418
Non-current assets - discontinued operations	2,961
Current portion of long term debt and capital leases	704
Other current liabilities	506
Current liabilities - discontinued operations	1,210
Long-term debt and capital leases	2,050
Out-of-market contracts	811
Other non-current liabilities	323
Non-current liabilities - discontinued operations	$	3,184

Chapter 11 Cases

Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. There is no assurance that the GenOn Entities' plan will be successfully implemented. The principal terms of the Restructuring Support Agreement are described further below.

On September 18, 2017, and October 2, 2017, the GenOn Entities filed amendments to the plan of reorganization and the disclosure statement which primarily provided the GenOn Entities with the flexibility to complete sales of certain assets pursuant to the amended plan of reorganization and removed the GenOn Entities' requirement to conduct a rights offering in connection with the GenOn Entities' exit financing.

On October 31, 2017, the GenOn Entities announced that they entered into a Consent Agreement with certain holders of GenOn’s Senior Notes and GenOn Americas Generation's Senior Notes, collectively, the Consenting Holders, whereby the GenOn Entities and the Consenting Holders agreed to extend the milestones in the Restructuring Support Agreement, by which the plan of reorganization must become effective, or the Effective Date. Specifically, the Consent Agreement extended the Effective Date milestone to June 30, 2018, or September 30, 2018, if regulatory approvals are still pending, or the Extended Effective Dates.

On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization, and effective December 12, 2017, GenOn and NRG entered into agreements concerning (i) timeline and transition, (ii) cooperation and co-development matters, (iii) post-employment and retiree health and welfare benefits and pension benefits, (iv) tax matters, and (v) intercompany balances and releases, consistent with the Restructuring Support Agreement, which among other things, provide for the transition of GenOn to a standalone enterprise, the resolution of substantial intercompany claims between GenOn and NRG, and the allocation of certain costs and liabilities between GenOn and NRG. On December 12, 2017, the Bankruptcy Court also entered an order giving effect to the Consent Agreement.

Forms of certain of the definitive documents that make up the plan supplement were filed with the Bankruptcy Court by the GenOn Entities and approved by the Bankruptcy Court in connection with the confirmation of the plan of reorganization. It is a condition precedent to the occurrence of the effective date of the plan of reorganization that the final version of the plan supplement be consistent with the Restructuring Support Agreement, in all material respects.

Restructuring Support Agreement

As described in Note 1, Nature of Business, NRG, GenOn and certain holders representing greater than 93% in aggregate principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization that was approved by the Bankruptcy Court pursuant to an order of confirmation. Completion of the agreed upon terms is contingent upon certain milestones in the Restructuring Support Agreement and the satisfaction or waiver or certain conditions precedent. Certain principal terms of the Restructuring Support Agreement and the plan of reorganization are detailed below:


1)	The dismissal of litigation and full releases from GenOn and GenOn Americas Generation in favor of NRG upon the earlier of the consummation of the GenOn Entities' plan of reorganization or the Settlement Agreement; a condition precedent to the consummation of the Settlement Agreement is a full release or indemnification in favor of NRG from any claims of GenOn Mid-Atlantic and REMA.

NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of December 31, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. See Note 21, Related Party Transactions, for further discussion of the intercompany secured revolving credit facility.


3)	NRG will consent to the cancellation of its interests in the equity of GenOn and be entitled to a worthless stock deduction, as further described in the tax matters agreement. The equity interests in the reorganized GenOn will be issued to the holders of the GenOn Senior Notes.

NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of December 31, 2017, was approximately $92 million. NRG will also retain the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million.

The shared services agreement between NRG and GenOn was terminated and replaced as of the plan confirmation date with a transition services agreement. Under the transition services agreement, NRG will continue to provide the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments. See Note 21, Related Party Transactions, for further discussion of the Services Agreement.


6)	NRG will provide a credit of $28 million to GenOn to apply against amounts owed under the transition services agreement. Any unused amount can be paid in cash at GenOn’s request. The credit was intended to reimburse GenOn for its payment of financing costs.

NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn had obtained a separate letter of credit facility with a third party financial institution. See Note 21, Related Party Transactions, for further discussion of the intercompany secured revolver credit facility and the letter of credit facility obtained in July 2017.


8)	NRG and GenOn have agreed to cooperate in good faith to maximize the value of certain development projects. Pursuant to this, GenOn made a one-time payment in the amount of $15 million to NRG in December 2017 as compensation for a purchase option with respect to the Canal 3 project.

Settlement Consideration

NRG has determined that the payment of the settlement consideration is probable and has recorded a liability for the amount due of $261.3 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. NRG expects to pay this amount net of amounts due from GenOn under the intercompany secured revolving credit facility, which is further described in Note 21, Related Party Transactions.

Pension Liability

NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, which was paid in September 2017, for the GenOn employees for service provided prior to emergence from bankruptcy. NRG determined that the retention of this liability is probable and has recorded the estimated accumulated pension benefit obligation as of December 31, 2017 of $92 million in other non-current liabilities with a corresponding loss from discontinued operations. NRG's obligation for this liability will be revalued through and at GenOn's emergence from bankruptcy.

Services Agreement

Beginning on June 14, 2017, and through December 2017, NRG recorded amounts earned for shared services of approximately $5 million per month. In December 2017, NRG provided GenOn with a $3.5 million credit for services provided under the transition services agreement and began recording amounts earned for shared services of approximately $7 million per month. NRG has also agreed to provide GenOn with a credit of $28 million against amounts owed under the transition services agreement. Any unused amount can be paid in cash at GenOn’s request, subject to the terms and conditions of the transition services agreement. As a result, NRG has concluded that the liability for this credit is probable and has recorded a payable to GenOn for $28 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations.

Commercial Operations

For pre-disposal periods, NRG provided GenOn with services as described in Note 21, Related Party Transactions. Under intercompany agreements, NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. For current and pre-disposal periods, revenue and expense associated with these transactions is recorded in continuing operations.

GenOn Debt

As of June 14, 2017, the GenOn Senior Notes and GenOn Americas Generation Senior Notes, which totaled approximately $2.5 billion, were deconsolidated from NRG's consolidated financial statements. The filing of the Chapter 11 Cases constitutes an event of default under the following debt instruments of GenOn:


1)	The intercompany secured revolving credit facility with NRG;


2)	The indenture governing the GenOn 7.875% Senior Notes due 2017 (as amended or supplemented from time to time);


3)	The indenture governing the GenOn 9.500% Notes due 2018 (as amended or supplemented from time to time);


4)	The indenture governing the GenOn 9.875% Notes due 2020 (as amended or supplemented from time to time);


5)	The indenture governing the GenOn Americas Generation 8.50% Senior Notes due 2021 (as amended or supplemented from time to time); and


6)	The indenture governing the GenOn Americas Generation 9.125% Senior Notes due 2031 (as amended or supplemented from time to time).

Dispositions

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. As part of the sale, 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 $25 million remains as of December 31, 2017. On February 22, 2017, the Company and CPUC entered into a second amendment to the agreement which extended the operating period commitment for the Freedom Stations to December 5, 2020. As of December 31, 2017, the Company's remaining 35% interest in EVgo of $1 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.

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.

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 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 PacifiCorp.

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, of which $20 million was paid as of December 31, 2017.

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 these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc. The purchase price was 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.

Transfers of Assets under Common Control

On November 1, 2017, NRG completed the sale of a 38-MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.

On August 1, 2017, NRG closed on the sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustment of $3 million. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.

On March 27, 2017, the Company sold to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity, which have reached commercial operations. NRG Yield, Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse debt of approximately $328 million.

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.

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 Instruments

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

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,
	2017				2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets
Notes receivable ^(a)	$	16	$	15	$	34	$	34
Liabilities
Long-term debt, including current portion ^(b)	$	16,603	$	16,894	$	16,655	$	16,620

(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, 2017 and 2016:



	As of December 31, 2017				As of December 31, 2016
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	8,934	$	7,960	$	9,205	$	7,415

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.

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, 2017
	Fair Value
	Total		Level 1		Level 2		Level 3
	(In millions)
Investments in securities (classified within other non-current assets):
Debt securities	$	19	$	—	$	—	$	19
Available-for-sale securities	3		3		—		—
Nuclear trust fund investments:
Cash and cash equivalents	47		45		2		—
U.S. government and federal agency obligations	43		42		1		—
Federal agency mortgage-backed securities	82		—		82		—
Commercial mortgage-backed securities	14		—		14		—
Corporate debt securities	99		—		99		—
Equity securities	334		334		—		—
Foreign government fixed income securities	5		—		5		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	745		191		509		45
Interest rate contracts	53		—		53		—
Measured using net asset value practical expedient:
Equity securities	68
Total assets	$	1,513	$	616	$	765	$	64
Derivative liabilities:
Commodity contracts	$	693	$	257	$	359	$	77
Interest rate contracts	59		—		59		—
Total liabilities	$	752	$	257	$	418	$	77



	As of December 31, 2016
	Fair Value
	Total		Level 1		Level 2		Level 3

Investments in securities (classified within other non-current assets):
Debt securities	$	17	$	—	$	—	$	17
Available-for-sale securities	10		10		—		—
Nuclear trust fund investments:
Cash and cash equivalents	25		25		—		—
U.S. government and federal agency obligations	73		72		1		—
Federal agency mortgage-backed securities	62		—		62		—
Commercial mortgage-backed securities	17		—		17		—
Corporate debt securities	84		—		84		—
Equity securities	292		292		—		—
Foreign government fixed income securities	3		—		3		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,199		560		549		90
Interest rate contracts	49		—		49		—
Measured using net asset value practical expedient:
Equity securities	54
Total assets	$	1,886	$	960	$	765	$	107
Derivative liabilities:
Commodity contracts	$	1,288	$	494	$	636	$	158
Interest rate contracts	88		—		88		—
Total liabilities	$	1,376	$	494	$	724	$	158

There have been no transfers during the year ended December 31, 2017 between Levels 1 and 2. The following tables reconcile, for the years ended December 31, 2017 and 2016, 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, 2017
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt Securities		Derivatives^(a)			Total
	(In millions)
Beginning balance as of January 1, 2017	$	17	$	(68	)	$	(51	)
Total gains/(losses) realized/unrealized:
Included in earnings	2		43			45
Included in nuclear decommissioning obligations	—		—			—
Purchases	—		(23		)	(23		)
Contracts reclassified to held-for-sale	—		4			4
Transfers into Level 3 ^(b)	—		(1		)	(1		)
Transfers out of Level 3 ^(b)	—		13			13
Ending balance as of December 31, 2017	$	19	$	(32	)	$	(13	)
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2017	$	2	$	6		$	8


(a)	Consists of derivatives assets and liabilities, net.


(b)	Transfers into/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 into/out of Level 3 are from/to Level 2.



	For the Year Ended December 31, 2016
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt Securities		Trust Fund Investments^(c)			Derivatives ^(a)			Total
	(In millions)
Beginning balance as of January 1, 2016	$	17	$	54		$	(22	)	$	49
Total gains/(losses) realized/unrealized:
Included in earnings	—		—			2			2
Included in nuclear decommissioning obligations	—		(1		)	—			(1		)
Purchases	—		1			(29		)	(28		)
Transfers into Level 3 ^(b)	—		—			(18		)	(18		)
Transfer out of Level 3 ^(b)	—		(54		)	(1		)	(55		)
Ending balance as of December 31, 2016	$	17	$	—		$	(68	)	$	(51	)
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	$	—	$	—		$	(13	)	$	(13	)


(a)	Consists of derivatives assets and liabilities, net.


(b)	Transfers into/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 into/out of Level 3 are from/to Level 2.


(c)	All Trust Fund Investments were considered transferred out of Level 3 as these investments are measured using net asset value as a practical expedient and are thus classified outside of the fair value hierarchy as of December 31, 2016.

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 6% of derivative assets and 10% 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, 2017, the credit reserve resulted in no change in fair value in operating revenue and cost of operations. As of December 31, 2016 the credit reserve resulted in a $10 million decrease in fair value 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, 2017, 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 executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power 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, 2017 and 2016:



	Significant Unobservable Inputs
	December 31, 2017
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	34	$	65	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	142	$	33
FTRs	11		12		Discounted Cash Flow	Auction Prices (per MWh)	(28		)	46		—
	$	45	$	77



	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	$	39	$	108	Discounted Cash Flow	Forward Market Price (per MWh)	$	11		$	104	$	31
FTRs	51		50		Discounted Cash Flow	Auction Prices (per MWh)	(22		)	17		—
	$	90	$	158

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2017 and 2016:



Significant Unobservable Input	Position	Change In Input	Impact on Fair Value Measurement
Forward Market Price Power	Buy	Increase/(Decrease)	Higher/(Lower)
Forward Market Price Power	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, 2017, the Company recorded $171 million of cash collateral posted and $37 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, 2017, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $220 million and NRG held collateral (cash and letters of credit) against those positions of $30 million, resulting in a net exposure of $196 million. Approximately 73% of the Company's exposure before collateral is expected to roll off by the end of 2019. 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)
Financial institutions	14	%
Utilities, energy merchants, marketers and other	86
Total	100	%



Category	Net Exposure^{(a) (b)} (% of Total)
Investment grade	69	%
Non-Investment grade/Non-Rated	31
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 $37 million as of December 31, 2017. 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, 2017, 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, 2017, 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 $68 million, $48 million, and $64 million for the years ending December 31, 2017, 2016, and 2015, 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.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Accounting for Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in 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, trades in support of NRG's baseload units may 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 derivative products used to mitigate a portion of 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, 2017, 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 2019; and


•	Other energy derivatives instruments extending through 2024.

Also, as of December 31, 2017, 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 2043;


•	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, 2017, NRG had interest rate derivative instruments on recourse debt extending through 2021 and non-recourse debt extending through 2041, some 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, 2017 and 2016. 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, 2017			December 31, 2016
		(In millions)
Emissions	Short Ton	1			—
Coal	Short Ton	21			35
Natural Gas	MMBtu	(17		)	(53		)
Oil	Barrel	—			1
Power	MWh	14			7
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	3,876		$	3,429
Equity	Shares	1			1

The decrease in the natural gas position was primarily the result of the settlement of generation hedge positions. The increase in the interest rate position was primarily the result of entering into new interest rate swaps to hedge additional non-recourse project level debt.

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, 2017		December 31, 2016		December 31, 2017		December 31, 2016
Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	1	$	—	$	5	$	28
Interest rate contracts long-term	11		12		11		41
Total Derivatives Designated as Cash Flow or Fair Value Hedges	12		12		16		69
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	9		—		15		7
Interest rate contracts long-term	32		37		28		12
Commodity contracts current	616		1,067		535		1,057
Commodity contracts long-term	129		132		158		231
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	786		1,236		736		1,307
Total Derivatives	$	798	$	1,248	$	752	$	1,376

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, 2017	(In millions)
Commodity contracts:
Derivative assets	$	745		$	(578	)	$	(11	)	$	156
Derivative liabilities	(693		)	578			73			(42		)
Total commodity contracts	52			—			62			114
Interest rate contracts:
Derivative assets	53			(3		)	—			50
Derivative liabilities	(59		)	3			—			(56		)
Total interest rate contracts	(6		)	—			—			(6		)
Total derivative instruments	$	46		$	—		$	62		$	108



	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	$	1,199		$	(1,021	)	$	(13	)	$	165
Derivative liabilities	(1,288		)	1,021			13			(254		)
Total commodity contracts	(89		)	—			—			(89		)
Interest rate contracts:
Derivative assets	49			(4		)				45
Derivative liabilities	(88		)	4			—			(84		)
Total interest rate contracts	(39		)	—			—			(39		)
Total derivative instruments	$	(128	)	$	—		$	—		$	(128	)

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, 2017
	Interest Rate			Total
	(In millions)
Accumulated OCI balance at December 31, 2016	$	(66	)	$	(66	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	12			12
Mark-to-market of cash flow hedge accounting contracts	—			—
Accumulated OCI balance at December 31, 2017, net of $8 tax	$	(54	)	$	(54	)
Losses expected to be realized from other comprehensive loss during the next 12 months, net of $2 tax	$	(12	)	$	(12	)



	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	)



	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	)

Amounts reclassified from accumulated OCI into income 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.

The Company's regression analysis for Marsh Landing, Walnut Creek and Avra Valley interest rate swaps, while positively correlated, no longer contain matching terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated the Marsh Landing, Walnut Creek and Avra Valley cash flow hedges as of April 28, 2017, 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 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, 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,
	2017			2016			2015
	(In millions)
Unrealized mark-to-market results
Reversal of previously recognized unrealized loss/(gains) on settled positions related to economic hedges	$	47		$	(128	)	$	(162	)
Reversal of acquired gain positions related to economic hedges	—			(12		)	(22		)
Net unrealized gains/(losses) on open positions related to economic hedges	146			6			(9		)
Total unrealized mark-to-market gains/(losses) for economic hedging activities	193			(134		)	(193		)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(25		)	10			(46		)
Reversal of acquired gain positions related to trading activity	—			—			(14		)
Net unrealized gains/(losses) on open positions related to trading activity	14			18			(16		)
Total unrealized mark-to-market (losses)/gains for trading activity	(11		)	28			(76		)
Total unrealized gains/(losses)	$	182		$	(106	)	$	(269	)



	Year Ended December 31,
	2017			2016			2015
	(In millions)
Unrealized gains/(losses) included in operating revenues	$	228		$	(614	)	$	(210	)
Unrealized (losses)/gains included in cost of operations	(46		)	508			(59		)
Total impact to statement of operations — energy commodities	$	182		$	(106	)	$	(269	)
Total impact to statement of operations — interest rate contracts	$	9		$	36		$	17

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, 2017, the $146 million gain from economic hedge positions was primarily the result of an increase in the value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.

For the year ended December 31, 2016, the $6 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.

For the year ended December 31, 2015, the $9 million loss from economic hedge positions was primarily the result of a decrease in the value of forward purchases of natural gas due to a decrease in natural gas prices.

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, 2017 was $25 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2017 was $7 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 $4 million as of December 31, 2017.

See Note 4, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.

Nuclear Decommissioning Trust Fund

12 Months Ended

Dec. 31, 2017

Nuclear Decommissioning Trust Fund Disclosure [Abstract]

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, 2017							As of December 31, 2016
(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	$	47	$	—	$	—	—	$	25	$	—	$	—	—
U.S. government and federal agency obligations	43		1		—		11	73		1		—		11
Federal agency mortgage-backed securities	82		1		1		23	62		1		1		25
Commercial mortgage-backed securities	13		—		—		20	17		—		1		26
Corporate debt securities	99		2		1		11	84		1		2		11
Equity securities	403		272		—		—	346		214		—		—
Foreign government fixed income securities	5		—		—		9	3		—		—		9
Total	$	692	$	276	$	2		$	610	$	217	$	4

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,
	2017		2016		2015
	(In millions)
Realized gains	$	22	$	26	$	21
Realized losses	8		11		14
Proceeds from sale of securities	501		510		631

Inventory

12 Months Ended

Dec. 31, 2017

Inventory Disclosure [Abstract]

Inventory

Inventory consisted of:



	As of December 31,
	2017		2016
	(In millions)
Fuel oil	$	90	$	142
Coal/Lignite	126		219
Natural gas	24		28
Spare parts	292		332
Total Inventory	$	532	$	721

During the year ended December 31, 2017, the Company recorded a lower of weighted average cost or market adjustment related to fuel oil of $33 million.

Notes Receivable

12 Months Ended

Dec. 31, 2017

Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]

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,
	2017		2016
	(In millions)
Notes receivable	$	16	$	34
Less current maturities^(a)	14		18
Total notes receivable — non-current	$	2	$	16


(a)	The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

- Definition

The entire disclosure for claims held for amounts due a entity, excluding financing receivables. Examples include, but are not limited to, trade accounts receivables, notes receivables, loans receivables. Includes disclosure for allowance for credit losses.

+ References + Details

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

The Company's major classes of property, plant, and equipment were as follows:



	As of December 31,						Depreciable
	2017			2016			Lives
	(In millions)
Facilities and equipment	$	15,907		$	18,698		1-40 Years
Land and improvements	710			750
Nuclear fuel	236			226			5 Years
Office furnishings and equipment	434			412			2-10 Years
Construction in progress	1,086			619
Total property, plant, and equipment	18,373			20,705
Accumulated depreciation	(4,465		)	(5,336		)
Net property, plant, and equipment	$	13,908		$	15,369

The Company recorded long-lived asset impairments during the years ended December 31, 2017 and 2016, as further described in Note 10, Asset Impairments.

Asset Impairments	12 Months Ended
Asset Impairments	Dec. 31, 2017
Asset Impairment Charges [Abstract]
Asset Impairments	Asset Impairments 2017 Impairment Losses During the fourth quarter of 2017, the Company completed its annual budget and revised its view of long-term power and fuel prices and the corresponding impact on estimated cash flows associated with its long-lived assets. The most significant impact was a decrease in the Company's long-term view of natural gas prices which resulted in a reduction to long-term power prices and had a negative impact on the Company's coal, nuclear and renewable facilities. Each of the facilities below had estimated cash flows that were lower than the carrying amount and the assets were considered impaired. The fair values of the assets were determined using an income approach by applying a discounted cash flow methodology to the long-term budget for the facility. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, an include key inputs such as forecasted power prices, nuclear fuel costs, forecasted operating and maintenance costs, plant investment capital expenditures and discount rates. South Texas Project, or STP — The Company recognized an impairment loss of $1,248 million related to its interest in STP as a result of the decrease in the Company's view of long-term power prices in ERCOT. Indian River — The Company recognized an impairment loss of $36 million for Indian River as a result of the decrease in the Company's view of long-term power prices in PJM. Keystone and Conemaugh — The Company recognized impairment losses of $35 million for Keystone and $35 million for Conemaugh as a result of the decrease in the Company's view of long-term power prices in PJM. Wind Facilities — The Company recorded impairment losses of $110 million, $26 million and $4 million for Langford, Elbow Creek and Forward, respectively, as a result of the decrease in the Company's view of long-term merchant power prices in ERCOT and PJM. While Elbow Creek and Forward have contracts to sell power, the significant decrease in estimated power prices had an impact on cash flows in post-contract periods. The Company also recorded the following impairments in 2017 based on specific triggering events that occurred: Bacliff Project — On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to zero during the second quarter of 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages. Other Long-Lived Asset Impairments — During the second, third and fourth quarters of 2017, the Company recorded impairment losses of approximately $22 million, $14 million and $15 million, respectively, in connection with the Company's Renewables business. These impairment losses were primarily to record the value of certain long-lived assets, including property, plant and equipment and intangible assets, at fair market value at acquisition date or in connection with an impairment indicator. Petra Nova Parish Holdings — In connection with the preparation of the annual budget during the fourth quarter, management revised its view of oil production expectations with respect to Petra Nova Parish Holdings. 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 $69 million. The Company also recorded an additional $11 million in impairment losses for other investments during the fourth quarter of 2017. 2016 Impairment Losses Rockford — As described in Note 3, Discontinued Operations, 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. 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 extension in SCE's capacity auction during the fourth quarter of 2016 for the PPA set to 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. Subsequently, management decided to continue to operate in 2018, which did not significantly impact fair value. Other Impairments — During 2016, the Company recorded other impairment losses of $153 million, which included $23 million in excess SO₂allowances, $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 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.

Goodwill and Other Intangibles

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangibles

Goodwill

NRG's goodwill balance was $539 million and $662 million as of December 31, 2017 and 2016, respectively. As of December 31, 2017, and 2016, NRG had approximately $460 million and $547 million, respectively, of goodwill that is deductible for U.S. income tax purposes in future periods. As of December 31, 2017, goodwill consisted of $165 million associated with the acquisition of EME, $341 million for Retail business acquisitions, and $33 million associated with other business acquisitions.

2017 Impairments of Goodwill

BETM — During the fourth quarter of 2017, the Company concluded that BETM was held for sale in connection with board approval and advanced negotiations to sell the business. Accordingly, the Company recorded the assets and liabilities at fair market value as of December 31, 2017, which resulted in an impairment loss of $90 million to record BETM’s goodwill at fair market value. The remaining goodwill balance for BETM of $21 million is included within non-current assets held-for-sale as of December 31, 2017.

SPP — During the fourth quarter of 2017, NRG sold its interests in certain SPP projects to NRG Yield. The goodwill recorded during the SPP acquisition was related primarily to its development pipeline, which was not sold to NRG Yield. As the Company does not expect to separately develop these projects and accordingly, has no cash flow stream associated with the goodwill, an impairment loss of $12 million was recorded to reduce the value to zero as of December 31, 2017.

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.

Intangible Assets

The Company's intangible assets as of December 31, 2017, primarily reflect intangible assets established with the acquisitions of various companies and are comprised of the following:

•

Emission Allowances — These intangibles primarily consist of SO₂ and NO_x emission allowances established with the 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 SO₂ allowances and RGGI credits amortized based on units of production. During the year ended December 31, 2017, the Company recorded an impairment loss of $20 million to reduce the value of excess SO₂ 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, Energy Curtailment Specialists, and Source Power & Gas. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.


•	Marketing partnerships — Established with the acquisition of Energy Plus, 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. During the year ended December 31, 2017, the Company recorded an impairment loss of $6 million related to 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 assets related to purchased ground leases.

The following tables summarize the components of NRG's intangible assets subject to amortization:



				Contracts
Year Ended December 31, 2017	Emission Allowances			Energy Supply			Fuel			Customer			Customer Relationships			Marketing Partnerships			Trade Names			PPA			Other			Total
	(In millions)
January 1, 2017	$	789		$	54		$	72		$	16		$	816		$	88		$	342		$	1,286		$	198		$	3,661
Purchases	31			—			—			—			—			—			—			—			32			63
Acquisition of businesses	—			—			—			—			18			—			—			—			—			18
Usage	(10		)	—			—			—			—			—			—			—			(28		)	(38		)
Write-off of fully amortized balances^(a)	—			(54		)	(23		)	—			—			—			—			—			—			(77		)
Impairment	(20		)	—			—			—			—			—			—			(6		)	—			(26		)
Other	(23		)	—			—			—			—			—			—			5			(19		)	(37		)
December 31, 2017	767			—			49			16			834			88			342			1,285			183			3,564
Less accumulated amortization	(591		)	—			(45		)	(9		)	(698		)	(54		)	(182		)	(205		)	(34		)	(1,818		)
Net carrying amount	$	176		$	—		$	4		$	7		$	136		$	34		$	160		$	1,080		$	149		$	1,746

(a) Adjusted for write-off of fully amortized energy supply contracts of $54 million and fuel contracts of $23 million.



				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	$	816		$	54		$	72		$	16		$	834		$	88		$	342		$	1,286		$	213		$	3,721
Purchases	13			—			—			—			—			—			—			—			34			47
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	(6		)	—			—			—			—			—			—			—			—			(6		)
December 31, 2016	789			54			72			16			816			88			342			1,286			198			3,661
Less accumulated amortization	(518		)	(54		)	(67		)	(8		)	(663		)	(49		)	(159		)	(143		)	(27		)	(1,688		)
Net carrying amount	$	271		$	—		$	5		$	8		$	153		$	39		$	183		$	1,143		$	171		$	1,973

(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.

The following table presents NRG's amortization of intangible assets for each of the past three years:



	Years Ended December 31,
Amortization	2017		2016		2015
	(In millions)
Emission allowances	$	73	$	66	$	60
Energy supply contracts	—		7		5
Fuel contracts	1		2		2
Customer contracts	1		2		2
Customer relationships	35		49		67
Marketing partnerships	5		8		14
Trade names	23		22		23
Power purchase agreements	62		64		51
Other	7		11		14
Total amortization	$	207	$	231	$	238

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)
2018	$	33	$	1	$	1	$	25	$	5	$	22	$	64	$	8	$	159
2019	30		—		1		21		4		22		64		8		150
2020	16		—		1		17		4		22		64		8		132
2021	16		—		1		13		4		22		64		8		128
2022	15		—		1		7		3		22		64		8		120

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, 2017, the value of emission allowances held-for-sale is $9 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 acquired in the acquisition of EME. These out-of-market contracts are amortized to cost of operations. As of December 31, 2017 and 2016, the Company had accumulated amortization for out-of-market contracts of $358 million and $457 million, respectively.

The following table summarizes the estimated amortization related to NRG's out-of-market contracts:



Year Ended December 31,	Power Contracts		Leases		Total
	(In millions
2018	$	16	$	9	$	25
2019	16		9		25
2020	17		9		26
2021	14		9		23
2022	1		9		10

- Definition

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

Debt and Capital Leases

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt and Capital Leases

Long-term debt and capital leases consisted of the following:



(In millions, except rates)	December 31,						December 31, 2017
	2017			2016			Interest Rate % ^(a)
Recourse debt:
Senior notes, due 2018	$	—		$	398		7.625
Senior notes, due 2021	—			207			7.875
Senior notes, due 2022	992			992			6.250
Senior notes, due 2023	—			869			6.625
Senior notes, due 2024	733			733			6.250
Senior notes, due 2026	1,000			1,000			7.250
Senior notes, due 2027	1,250			1,250			6.625
Senior notes, due 2028	870			—			5.750
Term loan facility, due 2023	1,872			1,891			L+2.25
Tax-exempt bonds	465			455			4.125 - 6.00
Subtotal recourse debt	7,182			7,795
Non-recourse debt:
NRG Yield Operating LLC Senior Notes, due 2024	500			500			5.375
NRG Yield Operating LLC Senior Notes, due 2026	350			350			5.000
NRG Yield, Inc. Convertible Senior Notes, due 2019	345			345			3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020	288			288			3.250
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 ^(b)	55			—			L+2.500
El Segundo Energy Center, due 2023	400			443			L+1.75 - L+2.375
Marsh Landing, due 2023	318			370			L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035	926			965			5.696 - 7.015
Walnut Creek, term loans due 2023	267			310			L+1.625
Utah Portfolio, due 2022	278			287			L+2.625
Tapestry, due 2021	162			172			L+1.625
CVSR, due 2037	746			771			2.339 - 3.775
CVSR HoldCo, due 2037	194			199			4.680
Alpine, due 2022	135			145			L+1.750
Energy Center Minneapolis, due 2025	83			96			3.55 - 5.95
Energy Center Minneapolis, due 2031	125			125			3.55
Viento, due 2023	163			178			L+3.00
NRG Yield - other	579			603			various
Subtotal NRG Yield debt (non-recourse to NRG) ^(c)	5,914			6,147
Ivanpah, due 2033 and 2038	1,073			1,113			2.285 - 4.256
Carlsbad Energy Project ^(c)	427			—			L+1.625 -.04120
Agua Caliente, due 2037	818			849			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	89			—			5.430
Cedro Hill, due 2029 ^(c)	151			163			L+1.75
Midwest Generation, due 2019	152			231			4.390
NRG Other Renewables^(c)	647			269
NRG Other	180			137			various
Subtotal other non-recourse debt	3,537			2,762
Subtotal all non-recourse debt	9,451			8,909
Subtotal long-term debt (including current maturities)	16,633			16,704
Capital leases	5			6			various
Subtotal long-term debt and capital leases (including current maturities)	16,638			16,710
Less current maturities	(688		)	(516		)
Less debt issuance costs	(204		)	(188		)
Discounts	(30		)	(49		)
Total long-term debt and capital leases	$	15,716		$	15,957


(a)	As of December 31, 2017, L+ equals 3 month LIBOR plus x%, except for the Utah Solar Portfolio where L+ equals 1 month LIBOR plus 2.629%.


(b)	Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement


(c)	Debt associated with the asset sales announced in February 2018

Long-term debt includes the following discounts:



	As of December 31,
	2017			2016
	(In millions)
Term loan facility, due 2023 ^(a)	$	(7	)	$	(9	)
Yield, Inc. Convertible notes, due 2019	(5		)	(10		)
Yield, Inc. Convertible notes, due 2020	(13		)	(17		)
Midwest Generation, due 2019	(5		)	(13		)
Total discounts	$	(30	)	$	(49	)


(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.

Consolidated Annual Maturities

Annual payments based on the maturities of NRG's debt and capital leases for the years ending after December 31, 2017 are as follows:



	(In millions)
2018	$	695
2019	933
2020	805
2021	606
2022	1,854
Thereafter	11,745
Total	$	16,638

Recourse Debt

Senior Notes

Issuance of 2028 Senior Notes

On December 7, 2017, NRG issued $870 million of aggregate principal amount at par of 5.75% senior unsecured notes due 2028. The 2028 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on July 15, 2018, until the maturity date of January 15, 2028. The proceeds from the issuance of the 2028 Senior Notes were utilized to redeem the Company's 6.625% Senior Notes due 2023.

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 during 2016.

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.

2017 Senior Note Redemptions

During the year ended December 31, 2017, the Company redeemed $1.5 billion in aggregate principal of its Senior Notes for $1.5 billion, which included accrued interest of $29 million. In connection with the redemptions, a $49 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $7 million.



	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
Amount in millions, except rates
7.625% senior notes due 2018	$	398	$	411	101.42	%
7.875% senior notes due 2021	206		218		102.63	%
6.625% senior notes due 2023	869		915		103.57	%
Total	$	1,473	$	1,544

(a) Includes payment for accrued interest.

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.

Senior Notes Outstanding

As of December 31, 2017, NRG had the following outstanding issuances of senior notes, or Senior Notes:

i.6.250% senior notes, issued January 27, 2014 and due July 15, 2022, or the 2022 Senior Notes;

ii.6.250% senior notes, issued April 21, 2014 and due November 1, 2024, or the 2024 Senior Notes;

iii.7.250% senior notes, issued May 23, 2016 and due May 15, 2026, or the 2026 Senior Notes;

iv.6.625% senior notes, issued August 2, 2016 and due January 15, 2027, or the 2027 Senior Notes; and

v.5.750% senior notes, issued December 7, 2017 and due January 15, 2028, or the 2028 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.

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	%

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	%

2028 Senior Notes

At any time prior to January 15, 2021, NRG may redeem up to 35% of the aggregate principal amount of the 2028 Senior Notes, at a redemption price equal to 105.750% 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 January 15, 2023 NRG may redeem all or a part of the 2028 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 102.875% of the note, plus interest payments due on the note from the date of redemption through January 15, 2023 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after January 15, 2023, 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
January 15, 2023 to January 14, 2024	102.875	%
January 15, 2024 to January 14, 2025	101.917	%
January 15, 2025 to January 14, 2026	100.958	%
January 15, 2026 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 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 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 Senior Credit Facility's lenders.

The Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG's affiliates that have non-recourse debt financing, including GenOn, 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,
	2017		2016		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	32		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	$	465	$	455

Non-Recourse Debt

The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2017. All of NRG's non-recourse debt is secured by the assets in the respective project subsidiaries as further described below.

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, 2017, there was $55 million outstanding on the revolver and $74 million of letters of credit issued under the revolving credit facility.

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, 2017.

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.

Carlsbad Project Financing

On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of December 31, 2017, all $407 million of these notes were outstanding.

Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The Carlsbad Financing Agreement also includes a letter of credit facility with an aggregate principle amount not to exceed $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million. As of December 31, 2017, $20 million was outstanding under the construction loan and $29 million in in letters of credit in support of the project were issued.

Utah Portfolio

As part of the November 2, 2016 utility-scale solar and wind acquisition, as discussed in Note 3, Discontinued Operations, 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 lease financing arrangements

Alta Wind Holdings (Alta Wind II - V) and Alta I have finance lease obligations issued under lease transactions whereby the respective operating entities sold and leased back undivided interests in specific assets of the projects. All of the assets of Alta I-V are pledged as collateral under these arrangements. The sale and related lease transactions are accounted for as financing arrangements as the operating entities have continued involvement with the property.



Amount in millions, except rates	Lease Financing Arrangement				Letter of Credit Facility
Non-Recourse Debt	Amount Outstanding as of December 31, 2017		Interest Rate	Maturity Date	Amount Outstanding as of December 31, 2017		Interest Rate	Maturity Date
Alta Wind I	$	231	7.015%	12/30/2034	$	16	3.00% - 3.25%	1/5/2021
Alta Wind II	183		5.696%	12/30/2034	27		1.250%	3/21/2022
Alta Wind III	191		6.067%	12/30/2034	27		1.750%	various
Alta Wind IV	123		5.938%	12/30/2034	19		1.750%	various
Alta Wind V	198		6.071%	6/30/2035	30		1.750%	various
Total	$	926			$	119

Midwest Generation

On April 7, 2016, Midwest Generation, LLC, or MWG, entered into an agreement to sell certain quantities of unforced capacity that has cleared various PJM Reliability Pricing Model auctions to a trading counterparty for net proceeds of $253 million. MWG will continue to operate the applicable generation facilities and remains responsible for performance penalties and eligible for performance bonus payments, if any. Accordingly, MWG will continue to account for all revenues and costs as before; however, the proceeds will be recorded as a financing obligation while capacity payments by PJM to the counterparty will be reflected as debt amortization and interest expense through the end of the 2018/19 delivery year. MWG will amortize the upfront discount to interest expense, at an effective interest rate of 4.39%, over the term of the arrangement, through June 2019. As of December 31, 2017, $152 million was outstanding.

CVSR

On July 15, 2016, CVSR Holdco LLC, the indirect owner of the CVSR project, issued $200 million of senior secured notes. The $199 million of net proceeds from the notes were distributed to a subsidiary of NRG and NRG Yield Operating LLC, the owners of CVSR Holdco LLC, based on their pro-rata ownership. The notes were issued at par and bear an interest rate at 4.68%. Interest is payable semi-annually beginning on September 30, 2016, until the maturity date of March 31, 2037.

Capistrano Refinancing

On July 13, 2016, Cedro Hill, Broken Bow and Crofton Bluffs, subsidiaries of Capistrano Wind Partners, each amended their respective credit facilities to increase borrowings to a total of $312 million and to lower their respective interest rates. The net proceeds of $87 million were distributed to Capistrano Wind Partners and subsequently distributed to the holders of the Class B preferred equity interests of Capistrano Wind Partners.

Interest Rate Swaps — Project Financings

Many of NRG's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap payments by the project subsidiary and its counterparty are made quarterly, and the LIBOR is determined in advance of each interest period. The following table summarizes the swaps, some of which are forward starting as indicated, related to NRG's project level debt as of December 31, 2017.



	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2017 (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	%	various		3-mo. LIBOR	340		various	various
South Trent Wind LLC	75	%	3.265	%	3-mo. LIBOR	40		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	26		September 30, 2011	December 31, 2029
NRG Solar Alpine LLC	85	%	various		3-mo. LIBOR	115		various	various
NRG Solar Avra Valley LLC	85	%	2.333	%	3-mo. LIBOR	46		November 30, 2012	November 30, 2030
NRG Marsh Landing	75	%	3.244	%	3-mo. LIBOR	295		June 28, 2013	June 30, 2023
Utah Portfolio	80	%	various		1-mo. LIBOR	223		various	September 30, 2036
DGPV 4	85	%	various		3-mo. LIBOR	95		various	various
Other	75	%	various		various	653		various	various
EME Project Financings						—
Broken Bow	75	%	various		3-mo. LIBOR	55		various	various
Cedro Hill	90	%	various		3-mo. LIBOR	136		various	various
Crofton Bluffs	75	%	various		3-mo. LIBOR	36		various	various
Laredo Ridge	75	%	2.310	%	3-mo. LIBOR	75		March 31, 2011	March 31, 2026
Tapestry	75	%	2.210	%	3-mo. LIBOR	146		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	148		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	239		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-mo. LIBOR	45		June 28, 2013	May 21, 2023
Alta Wind Project Financings
AWAM	100	%	2.470	%	3-mo. LIBOR	17		May 22, 2013	May 15, 2031
Total						$	3,876

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

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, 2017 and 2016, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2017:



	(In millions)
Balance as of December 31, 2016	$	735
Revisions in estimates for current obligations	(3		)
Additions	9
Spending for current obligations	(21		)
Accretion — Expense	35
Accretion — Nuclear decommissioning	16
Balance as of December 31, 2017	$	771

Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

NRG sponsors and operates defined benefit pension and other postretirement plans.

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. 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.

NRG maintains two separate qualified pension plans, the NRG Pension Plan for Bargained Employees and the NRG Pension Plan. Employees of both NRG and GenOn participate in each of the pension plans, depending upon whether their employment is covered by a bargaining 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 pension liabilities associated with GenOn employees.

As described in Note 1, Nature of Business, and Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG and GenOn entered into a Restructuring Support Agreement and various support agreements, including a transition services agreement, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization and was approved by the Bankruptcy Court pursuant to an order of confirmation on December 12, 2017. In accordance with the agreements, NRG will retain GenOn's pension liability for service provided by GenOn employees prior to the completion of the reorganization. NRG determined that the retention of this liability is probable and has recorded the estimated accumulated pension benefit obligation as of December 31, 2017 of $92 million in other non-current liabilities with a corresponding loss from discontinued operations. The balance reflects a contribution of $13 million to the plans with respect to GenOn's employees paid in September 2017. NRG will also retain the liability for GenOn's post-employment and retiree health and welfare benefits, in an amount up to $25 million. Retention of this liability is probable and accordingly, NRG has recorded the $25 million in other non-current liabilities with a corresponding loss from discontinued operations as of December 31, 2017. NRG's obligation for both of these liabilities will be revalued through and at GenOn's emergence from bankruptcy, with NRG's obligation for the post-employment and retiree health and welfare plan capped at $25 million.

NRG expects to contribute $31 million to the Company's pension plans in 2018. Of this amount, $13 million related to employees of GenOn.

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
	2017			2016			2015
	(In millions)
Service cost benefits earned	$	26		$	30		$	32
Interest cost on benefit obligation	43			43			53
Expected return on plan assets	(58		)	(60		)	(62		)
Amortization of unrecognized net loss	4			2			2
Net periodic benefit cost	$	15		$	15		$	25



	Year Ended December 31,
	Other Postretirement Benefits
	2017			2016			2015
	(In millions)
Service cost benefits earned	$	1		$	2		$	3
Interest cost on benefit obligation	4			6			9
Amortization of unrecognized prior service credit	(9		)	(5		)	(5		)
Amortization of unrecognized net (gain)/loss	(1		)	—			1
Curtailment gain	—			—			(14		)
Net periodic benefit (credit)/cost	$	(5	)	$	3		$	(6	)

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
	2017			2016			2017			2016
	(In millions)
Benefit obligation at January 1	$	1,241		$	1,196		$	128		$	178
Service cost	26			30			1			2
Interest cost	43			43			4			6
Plan amendments	—			—			(1		)	(42		)
Actuarial loss/(gain)	77			40			6			(2		)
Employee and retiree contributions	—			—			3			3
Benefit payments	(58		)	(68		)	(13		)	(17		)
Benefit obligation at December 31	1,329			1,241			128			128
Fair value of plan assets at January 1	953			916			—			—
Actual return on plan assets	173			72			—			—
Employee and retiree contributions	—			—			3			3
Employer contributions	36			33			10			14
Benefit payments	(58		)	(68		)	(13		)	(17		)
Fair value of plan assets at December 31	1,104			953			—			—
Funded status at December 31 — excess of obligation over assets	$	(225	)	$	(288	)	$	(128	)	$	(128	)
Less: GenOn postretirement obligation^(a)	—			—			38			46
Add: Retained obligation in bankruptcy proceeding^(a)	—			—			(25		)	(25		)
Net obligation for NRG	$	(225	)	$	(288	)	$	(115	)	$	(107	)


(a)	The difference between GenOn's postretirement benefit obligation and NRG's retained obligation of $13 million and $21 million is presented in noncurrent liabilities for discontinued operations as of December 31, 2017 and 2016, respectively.

Amounts recognized in NRG's balance sheets were as follows:



	As of December 31,
	Pension Benefits				Other Postretirement Benefits
	2017		2016		2017			2016
	(In millions)
Current liabilities	$	—	$	—	$	7		$	8
Less: GenOn other postretirement benefits^(a)	—		—		(3		)	(5		)
Total current liabilities	$	—	$	—	$	4		$	3

Non-current liabilities	$	225	$	288	$	121		$	120
Less: GenOn other postretirement benefits^(a)	—		—		(10		)	(16		)
Total non-current liabilities	$	225	$	288	$	111		$	104


(a)	The difference between GenOn's postretirement benefit obligation and NRG's retained obligation of $13 million and $21 million is presented in noncurrent liabilities for discontinued operations as of December 31, 2017 and 2016, respectively.

Of the amounts recognized in NRG's balance sheet, $92 million and $120 million related to GenOn's pension benefits obligation as of December 31, 2017 and 2016, respectively, and $25 million related to GenOn's postretirement benefits obligation as of December 31, 2017 and 2016.

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
	2017			2016			2017			2016
	(In millions)
Net loss/(gain)	$	53		$	94		$	(4	)	$	(11	)
Prior service cost/(credit)	3			3			(37		)	(45		)
Total accumulated OCI	$	56		$	97		$	(41	)	$	(56	)
Less: GenOn (deconsolidated June 14, 2017)	(22		)	(37		)	10			8
Net accumulated OCI	$	34		$	60		$	(31	)	$	(48	)

Other changes in plan assets and benefit obligations recognized in OCI were as follows:



	Year Ended December 31,
	Pension Benefits						Other Postretirement Benefits
	2017			2016			2017			2016
	(In millions)
Net actuarial (gain)/loss	$	(37	)	$	28		$	6		$	(2	)
Amortization of net actuarial (gain)/loss	(4		)	(2		)	1			—
Prior service credit	—			—			(1		)	(41		)
Amortization of prior service cost	—			—			9			5
Total recognized in OCI	$	(41	)	$	26		$	15		$	(38	)
Less: GenOn (deconsolidated June 14, 2017)	15			$	(17	)	$	2		$	3
Net recognized in OCI	$	(26	)	$	9		$	17		$	(35	)
Less: GenOn (deconsolidated June 14, 2017)	15			(17		)	3			3
Net recognized in net periodic pension (credit)/cost and OCI	$	(11	)	$	24		$	13		$	39

As a result of GenOn's deconsolidation during 2017, NRG reduced the loss recorded in other comprehensive income by $28 million related to GenOn's pension and other postretirement benefits.

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 less than $1 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 less than $1 million and $7 million, respectively.

The following table presents the balances of significant components of NRG's pension plan:



	As of December 31,
	Pension Benefits
	2017		2016
	(In millions)
Projected benefit obligation	$	1,329	$	1,241
Accumulated benefit obligation	1,255		1,174
Fair value of plan assets	1,104		953

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, 2017
	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	$	—	$	256	$	256
Common/collective trust investment — non-U.S. equity	—		66		66
Common/collective trust investment — non-core assets	—		178		178
Common/collective trust investment — fixed income	—		230		230
Short-term investment fund	5		—		5
Subtotal fair value	$	5	$	730	$	735
Measured at net asset value practical expedient
Common/collective trust investment — non-U.S. equity					94
Common/collective trust investment — fixed income					233
Partnerships/joint ventures					42
Total fair value					$	1,104



	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	—		71		71
Common/collective trust investment — global equity	—		104		104
Common/collective trust investment — fixed income	—		190		190
Short-term investment fund	3		—		3
Subtotal fair value	$	3	$	648	$	651
Measured at net asset value practical expedient
Common/collective trust investment — non-U.S. equity					78
Common/collective trust investment — fixed income					193
Partnerships/joint ventures					31
Total fair value					$	953

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 trust investments is valued at fair value which is equal to the sum of the market value of all of the fund's underlying investments. Certain common/collective trust investments have readily determinable fair value as they publish daily net asset value, or NAV, per share and are categorized as Level 2. Certain other common/collective trust investments and partnerships/joint ventures use NAV per share, or its equivalent, as a practical expedient for valuation, and thus have been removed from the fair value hierarchy table.

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	2017		2016		2017		2016
Discount rate	3.71	%	4.26	%	3.71	%	4.29	%
Rate of compensation increase	3.00	%	3.00	%	N/A		N/A
Health care trend rate	—		—		8.2% grading to 4.5% in 2025		7.0% 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	2017		2016		2015		2017		2016		2015
Discount rate	4.26	%	4.52	%	4.16	%	4.29	%	4.55	%	4.20	%
Expected return on plan assets	6.85	%	6.65	%	6.36	%	—		—		—
Rate of compensation increase	3.00	%	3.00	%	3.45	%	—		—		—
Health care trend rate	—		—		—		7.0% grading to 5.0% in 2025		7.25% grading to 5.0% in 2025		8.6% grading to 5.0% in 2023

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, 2017:



U.S. equity	22	%
Non-U.S. equity	14	%
Non-core assets	19	%
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
Non-core assets^(a)		Various (per underlying asset class)
Fixed income securities		Barclays Capital Long Term Government/Credit Index & Barclays Strips 20+ Index

(a)

Non-Core Assets are defined as diversifying asset classes approved by the Investment Committee that are intended to enhance returns and/or reduce volatility of the U.S. and non-U.S. equities. Asset classes considered Non-Core include, but may not be limited to: Emerging Market Equity, Emerging Market Debt, Non-US Developed Market Small Cap, High Yield Fixed Income, Real Estate, Bank Loans, Global Infrastructure and other Alternatives.

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)
2018	$	68	$	7	$	—
2019	71		8		—
2020	75		8		—
2021	79		8		—
2022	82		8		—
2023-2027	421		33		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, 2017, NRG reimbursed STPNOC $8 million towards its defined benefit plans. For the year ended December 31, 2016, NRG reimbursed STPNOC $7 million towards its defined benefit plans. In 2018, NRG expects to reimburse STPNOC $6 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
	2017			2016			2017			2016
	(In millions)
Funded status — STPNOC benefit plans	$	(76	)	$	(74	)	$	(24	)	$	(23	)
Net periodic benefit cost/(credit)	8			7			(3		)	(2		)
Other changes in plan assets and benefit obligations recognized in other comprehensive (loss)/income	(6		)	11			5			(1		)

Defined Contribution Plans

NRG's employees are also eligible to participate in defined contribution 401(k) plans.

The Company's contributions to these plans were as follows:



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Company contributions to defined contribution plans	$	56	$	55	$	53

Capital Structure

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Capital Structure

For the period from December 31, 2014 to December 31, 2017, 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, 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
Shares issued under ESPP	—	560,769		560,769
Shares issued under LTIPs	739,309	—		739,309
Balance as of December 31, 2017	418,323,134	(101,580,045	)	316,743,089

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, 2017:



Equity Instrument	Common Stock Reserve Balance
Long-term incentive plans	19,597,433

Common stock dividends — In 2015, NRG paid quarterly dividends on the Company's common stock of $0.145 per share, or $0.58 per share on an annualized basis. 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 for 2016 and 2017. The following table lists the dividends paid per common share during 2017, 2016 and 2015:



	Fourth Quarter		Third Quarter		Second Quarter		First Quarter
2017	$	0.030	$	0.030	$	0.030	$	0.030
2016	$	0.030	$	0.030	$	0.030	$	0.145
2015	$	0.145	$	0.145	$	0.145	$	0.145

On January 19, 2018, 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, 2018, to stockholders of record as of February 1, 2018.

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, 2017, there remained 3,107,050 shares of treasury stock reserved for issuance under the ESPP, and in January of 2018, 175,862 shares of common stock were issued to employee accounts from treasury stock for the offering period of July 1, 2017 to December 31, 2017. Beginning January 2018, NRG suspended the ESPP.

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 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, 2017, 2016, and 2015:



	(In millions)
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	—
Balance as of December 31, 2017	$	—

Investments Accounted for by the Equity Method and Variable Interest Entities

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

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, 2017:



Name	Economic Interest		Investment Balance
			(In millions)
Avenal Solar Holdings LLC ^(a)	50.0	%	$	(6	)
Desert Sunlight Investment Holdings, LLC ^(a)	25.0	%	272
Elkhorn Ridge Wind, LLC ^(a)	47.0	%	73
GenConn Energy LLC ^(a)	50.0	%	102
Four Brothers Solar, LLC^(a)(c)	50.0	%	213
Granite Mountain Holdings, LLC ^(a)(c)	50.0	%	78
Iron Springs Holdings, LLC^(a)(c)	50.0	%	54
Midway-Sunset Cogeneration Company	50.0	%	16
San Juan Mesa Wind Project, LLC ^(a)	75.0	%	66
Watson Cogeneration Company	49.0	%	21
Gladstone Power Station ^(b)	37.5	%	139
Other^(d)	Various		10
Total equity investments in affiliates			$	1,038

(a) Equity method investments owned by NRG Yield

(b) Gladstone Power Station is located in Australia

(d) Refer to Note 10 - Asset Impairments for discussion of NRG's investment in Petra Nova Parish Holdings, LLC.



	As of December 31,
	2017		2016
	(In millions)
Undistributed earnings from equity investments	$	120	$	101

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.

Utility-Scale Solar Portfolio — As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, on November 2, 2016, the Company acquired equity interests in a tax equity financed portfolio comprised of 530 MW of mechanically-complete solar assets located in Utah, and subsequently sold these interests to NRG Yield, Inc. on March 27, 2017. These equity interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC are accounted for as equity method investments as the Company does not have a controlling financial interest. The assets reached commercial operations during the fourth quarter of 2016 and have 20-year PPAs with PacifiCorp. NRG's maximum exposure to loss is limited to its equity investment, which was $345 million as of December 31, 2017.

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, 2017, $204 million was outstanding under the note and $14 million of letters of credit issued under 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 $102 million as of December 31, 2017.

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 $139 million as of December 31, 2017.

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 $110 million as of December 31, 2017, 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, 2017		December 31, 2016
Current assets	$	118	$	87
Net property, plant and equipment	2,337		1,534
Other long-term assets	658		954
Total assets	3,113		2,575
Current liabilities	96		59
Long-term debt	661		442
Other long-term liabilities	209		183
Total liabilities	966		684
Redeemable noncontrolling interests	78		46
Noncontrolling interests	507		529
Net assets less noncontrolling interests	$	1,562	$	1,316

Earnings/(Loss) Per Share

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

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 year ended December 31, 2015. 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,
	2017			2016			2015
	(In millions, except per share amounts)
Basic and diluted loss per share attributable to NRG common stockholders
Net loss attributable to NRG Energy, Inc.	$	(2,153	)	$	(774	)	$	(6,382	)
Dividends for preferred shares	—			5			20
Gain on redemption of 2.822% redeemable perpetual preferred shares	—			(78		)	—
Loss Available to Common Stockholders	$	(2,153	)	$	(701	)	$	(6,402	)
Weighted average number of common shares outstanding	317			316			329
Loss per weighted average common share — basic and diluted	$	(6.79	)	$	(2.22	)	$	(19.46	)

The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted loss per share:



	Year Ended December 31,
	2017	2016	2015
	(In millions of shares)
Equity compensation	5	5	6
Embedded derivative of 2.822% redeemable perpetual preferred stock	—	—	16
Total	5	5	22

Segment Reporting

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Reporting

The Company's segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail, which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. Intersegment sales are accounted for at market.

NRG Yield includes certain of the Company's contracted generation assets. During 2017, NRG Yield acquired several projects totaling 555 MW for cash consideration of approximately $245 million from NRG. These acquisitions were treated as a transfer of entities under common control and accordingly, the financial information for years ended December 31, 2017, 2016, and 2015 have been recast to reflect these changes.

On June 14, 2017, as described in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG deconsolidated GenOn for financial reporting purposes. The financial information for years ended December 31, 2017, 2016, and 2015 have been recast to present GenOn as discontinued operations within the corporate segment.

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, 2017, 2016 and 2015, the Company had no customer which comprised more than 10% of the Company's consolidated revenues.



	For the Year Ended December 31, 2017
	Generation^(a)			Retail ^(a)			Renewables^(a)			NRG Yield^(a)			Corporate^(a)			Eliminations				Total
	(In millions)
Operating revenues^(a)	$	3,773		$	6,380		$	424		$	1,009		$	14		$	(971	)		$	10,629
Operating expenses	3,300			5,372			211			348			220			(964		)		8,487
Depreciation and amortization	377			117			196			334			32			—				1,056
Impairment losses	1,504			7			154			44			—			—				1,709
Development costs	13			2			45			—			7			—				67
Total operating cost and expenses	5,194			5,498			606			726			259			(964		)		11,319
Other income - affiliate	—			—			—			—			87			—				87
Gain/(loss) on sale of assets	20			—			(5		)	—			1			—				16
Operating (loss)/income	(1,401		)	882			(187		)	283			(157		)	(7		)		(587		)
Equity in (losses)/earnings of unconsolidated affiliates	(14		)	—			—			71			6			(32		)		31
Impairment losses on investments	(74		)	—			—			—			(5		)	—				(79		)
Other income, net	22			1			—			4			11			—				38
Loss on debt extinguishment	—			—			(1		)	(3		)	(49		)	—				(53		)
Interest expense	(29		)	(6		)	(98		)	(306		)	(451		)	—				(890		)
(Loss)/income from continuing operations before income taxes	(1,496		)	877			(286		)	49			(645		)	(39		)		(1,540		)
Income tax expense/(benefit)	2			(9		)	(20		)	72			(37		)	—				8
Net (loss)/income from continuing operations	$	(1,498	)	$	886		$	(266	)	$	(23	)	$	(608	)	$	(39	)		$	(1,548	)
Loss from discontinued operations, net of income tax	—			—			—			—			(789		)	—				$	(789	)
Net (Loss)/Income	(1,498		)	886			(266		)	(23		)	(1,397		)	(39		)		(2,337		)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests	—			2			(103		)	(87		)	(4		)	8				(184		)
Net (loss)/income attributable to NRG Energy, Inc.	$	(1,498	)	$	884		$	(163	)	$	64		$	(1,393	)	$	(47	)		$	(2,153	)

Balance sheet
Equity investments in affiliates	$	179		$	—		$	4		$	852		$	3		$	—			$	1,038
Capital expenditures ^(b)	481			82			521			31			12			—				1,127
Goodwill	165			374			—			—			—			—				539
Total assets	$	7,209		$	2,630		$	5,129		$	8,283		$	8,919		$	(8,852	)	—	$	23,318



(a) Inter-segment sales and net derivative gains and losses included in operating revenues	$	910	$	5	$	31	$	—	$	25	$	—	$	971

(b) Includes accruals.



	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)	$	3,833		$	6,335		$	406		$	1,035		$	77		$	(1,174	)	$	10,512
Operating expenses	3,545			5,164			217			325			323			(1,178		)	8,396
Depreciation and amortization	516			111			185			303			57			—			1,172
Impairment losses	430			1			54			185			32			—			702
Development costs	15			4			40			—			30			—			89
Total operating cost and expenses	4,506			5,280			496			813			442			(1,178		)	10,359
Other income - affiliate	—			—			—			—			193			—			193
Loss on sale of assets	—			(1		)	—			—			(79		)				(80		)
Operating (loss)/income	(673		)	1,054			(90		)	222			(251		)	4			266
Equity in (losses)/earnings of unconsolidated affiliates	(5		)	—			(58		)	60			13			17			27
Impairment losses on investments	(142		)	—			(105		)	—			(21		)	—			(268		)
Other income, net	21			(6		)	1			3			19			(4		)	34
Loss on debt extinguishment	—			—			—			—			(142		)	—			(142		)
Interest expense	(26		)	6			(98		)	(284		)	(495		)	2			(895		)
(Loss)/income from continuing operations before income taxes	(825		)	1,054			(350		)	1			(877		)	19			(978		)
Income tax (benefit)/expense	(1		)	1			(20		)	(1		)	26			—			5
Net (loss)/income from continuing operations	(824		)	1,053			(330		)	2			(903		)	19			(983		)
Income from discontinued operations, net of income tax	—			—			—			—			92						92
Net (Loss)/Income	(824		)	1,053			(330		)	2			(811		)	19			(891		)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	—			(2		)	(13		)	(54		)	18			(66		)	(117		)
Net (loss)/income attributable to NRG Energy, Inc.	$	(824	)	$	1,055		$	(317	)	$	56		$	(829	)	$	85		$	(774	)

Balance sheet
Equity investments in affiliates	$	204		$	—		$	26		$	886		$	4		$	—		$	1,120
Capital expenditures^(b)	522			12			330			23			110			—			997
Goodwill	276			374			12			—			—			—			662
Total assets	$	13,514		$	2,332		$	4,921		$	8,962		$	11,891		$	(10,938	)	$	30,682



(a) Inter-segment sales and net derivative gains and losses included in operating revenues	$	1,033	$	4	$	24	$	8	$	105	$	—	$	1,174

(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)	$	5,179		$	6,913		$	383		$	968		$	38		$	(1,153	)	$	12,328
Operating expenses	4,198			6,138			187			338			502			(1,135		)	10,228
Depreciation and amortization	693			132			176			303			47			—			1,351
Impairment losses	4,655			36			13			1			133			22			4,860
Development costs	26			4			61			—			63			—			154
Total operating costs and expenses	9,572			6,310			437			642			745			(1,113		)	16,593
Other income - affiliate	—			—			—			—			193			—			193
Gain on postretirement benefits curtailment	21			—			—			—			—			—			21
Operating (loss)/income	(4,372		)	603			(54		)	326			(514		)	(40		)	(4,051		)
Equity in earnings/(losses)of unconsolidated affiliates	10			—			(7		)	31			—			2			36
Impairment losses on investments	(14		)	—			—			—			(42		)	—			(56		)
Other income, net	18			(4		)	3			3			13			(7		)	26
Loss on sale of equity method investment	—			—			—			—			(14		)	—			(14		)
Loss on debt extinguishment	—			—			—			(9		)	19			—			10
Interest expense	(25		)	2			(79		)	(267		)	(574		)	6			(937		)
(Loss)/income from continuing operations before income taxes	(4,383		)	601			(137		)	84			(1,112		)	(39		)	(4,986		)
Income tax expense/(benefit)	—			1			(18		)	12			1,350			—			1,345
Net (loss)/income from continuing operations	$	(4,383	)	600			(119		)	72			(2,462		)	(39		)	(6,331		)
Loss from discontinued operations, net of income tax	—			—			—			—			(105		)	—			(105		)
Net (Loss)/Income	(4,383		)	600			(119		)	72			(2,567		)	(39		)	(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.	$	(4,383	)	$	600		$	(125	)	$	53		$	(2,530	)	$	3		$	(6,382	)



(a) Inter-segment sales and net derivative gains and losses included in operating revenues	$	896	$	6	$	31	$	29	$	191	$	—	$	1,153

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

The income tax provision from continuing operations consisted of the following amounts:



	Year Ended December 31,
	2017			2016			2015
	(In millions, except percentages)
Current
State	$	19		$	6		$	9
Total — current	19			6			9
Deferred
U.S. Federal	(6		)	3			1,020
State	(7		)	(6		)	315
Foreign	2			2			1
Total — deferred	(11		)	(1		)	1,336
Total income tax expense	$	8		$	5		$	1,345
Effective tax rate	(0.5		)%	(0.5		)%	(27.0		)%

The following represents the domestic and foreign components of loss before income tax expense:



	Year Ended December 31,
	2017			2016			2015
	(In millions)
U.S.	$	(1,557	)	$	(989	)	$	(4,997	)
Foreign	17			11			11
Total	$	(1,540	)	$	(978	)	$	(4,986	)

A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate is as follows:



	Year Ended December 31,
	2017			2016			2015
	(In millions, except percentages)
Loss before income taxes	$	(1,540	)	$	(978	)	$	(4,986	)
Tax at 35%	(539		)	(342		)	(1,745		)
State taxes	19			—			(215		)
Foreign operations	2			10			1
Federal and state tax credits, excluding PTCs	—			—			(5		)
Tax Act - corporate income tax rate change	733			—			—
Valuation allowance due to corporate income tax rate change	(660		)	—			—
Valuation allowance - current period activities	482			398			3,023
Impact of non-taxable equity earnings	(5		)	22			(10		)
Book goodwill impairment	30			—			340
Net interest accrued on uncertain tax positions	—			1			(3		)
Production tax credits	(20		)	(26		)	(33		)
Recognition of uncertain tax benefits	(5		)	2			(15		)
Tax expense attributable to consolidated partnerships	4			(1		)	12
State rate change including true-up to current period activity	18			(59		)	(7		)
AMT refundable credit	(64		)	—			—
Other	13			—			2
Income tax expense	$	8		$	5		$	1,345
Effective income tax rate	(0.5		)%	(0.5		)%	(27.0		)%

For the year ended December 31, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to tax expense recorded from the revaluation of the existing net deferred tax asset and state taxes, partially offset by the change in valuation allowance, establishing the AMT credit receivable and the generation of PTC’s from various wind facilities. The tax expense recorded for revaluation of the net deferred tax asset is required to reflect the reduction in the corporate income tax rate from 35% to 21% in accordance with the Tax Cuts and Jobs Act of 2017, or the Tax Act.

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.

The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:



	As of December 31,
	2017			2016
	(In millions)
Deferred tax liabilities:
Emissions allowances	$	15		$	31
Derivatives, net	15			—
Cumulative translation adjustments	—			11
Investment in projects	231			378
Discount/premium on notes	2			5
Deferred financing costs	2			2
Discontinued operations	—			6
Total deferred tax liabilities	265			433
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	141			256
Difference between book and tax basis of property	596			530
Goodwill	38			83
Differences between book and tax basis of contracts	68			60
Pension and other postretirement benefits	74			122
Equity compensation	10			11
Bad debt reserve	14			12
U.S. capital loss carryforwards	1			1
U.S. Federal net operating loss carryforwards	596			728
Foreign net operating loss carryforwards	66			63
State net operating loss carryforwards	140			106
Foreign capital loss carryforwards	1			1
Federal and state tax credit carryforwards	376			446
Federal benefit on state uncertain tax positions	7			12
Intangibles amortization (excluding goodwill)	101			115
Derivatives, net	—			106
Inventory obsolescence	12			5
Other	—			7
Discontinued operations	—			2,093
Total deferred tax assets	2,241			4,757
Valuation allowance	(1,863		)	(2,032		)
Discontinued operations	—			(2,087		)
Total deferred tax assets, net of valuation allowance	378			638
Net deferred tax asset	$	113		$	205

The following table summarizes NRG's net deferred tax position:



	As of December 31,
	2017			2016
	(In millions)
Net deferred tax asset — noncurrent	$	134		$	225
Net deferred tax liability — noncurrent	(21		)	(20		)
Net deferred tax asset	$	113		$	205

The primary driver for the decrease in the net deferred tax asset from $205 million to $113 million is the revaluation of the ending balance utilizing a 21% corporate income tax rate instead of a 35% corporate income tax rate pursuant to the Tax Act as of December 22, 2017. NRG Energy, Inc.’s revaluation is completely offset by its valuation allowance. Since NRG Yield, Inc. does not have a valuation allowance against its net deferred tax asset, its ending balance remains at December 31, 2017. Additionally, due to GenOn's petition for bankruptcy on June 14, 2017, its inventory of deferreds is reclassed to discontinued operations for the year ended December 31, 2016 and is completely deconsolidated for the year ended December 31, 2017.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of December 31, 2017 and 2016, NRG recorded a net deferred tax asset of $1.9 billion and $2.2 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, including the potential impacts of the recently enacted Tax Act. In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, which addresses how a company may recognize provisional amounts for the effect of the changes related to the Tax Act. Consistent with that guidance, the Company recognized provisional amounts based upon our interpretation of the tax laws and estimates which require significant judgments.

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 $1.8 billion and $2.0 billion of tax assets as of December 31, 2017, and 2016, respectively, thus a valuation allowance has been recorded. The net deferred tax asset of $113 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, 2017, the Company had tax effected cumulative domestic NOLs consisting of carryforwards for federal income tax purposes of $596 million and state of $140 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 $66 million with no expiration date.

Valuation allowance — As of December 31, 2017, the Company's tax effected valuation allowance was $1.8 billion, consisting of domestic federal net deferred tax assets of approximately $1.5 billion, domestic state net deferred tax assets of $267 million, foreign net operating loss carryforwards of $66 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, 2017, NRG recorded a current tax payable of $7 million that represents a tax liability due for state income taxes. NRG has a tax receivable of $1 million, comprised of refunds due from state income tax estimated payments and return filings for 2017 and 2016, respectively.

Uncertain tax benefits

NRG has identified uncertain tax benefits whose after-tax value is $30 million for which, as of December 31, 2017 and 2016, NRG has recorded a non-current tax liability of $33 million and $37 million, respectively. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the year ended December 31, 2017, the Company recognized an expense of $1 million in interest. As of December 31, 2017 and 2016, NRG had cumulative interest and penalties related to these uncertain tax benefits of $3 million and $4 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,
	2017			2016
	(In millions)
Balance as of January 1	$	34		$	32
Increase due to current year positions	4			8
Decrease due to prior year positions	(8		)	—
Decrease due to settlements and payments	—			(6		)
Uncertain tax benefits as of December 31	$	30		$	34

Stock-Based Compensation

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Stock-Based Compensation

NRG Energy, Inc. Long-Term Incentive Plan

On April 27, 2017, the NRG LTIP was amended to increase the number of shares available for issuance by 3,000,000. As of December 31, 2017 and 2016, a total of 25,000,000 and 22,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP, respectively. There were 8,724,595 and 7,487,058 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 2017 and 2016, respectively. The NRG LTIP is 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.

Upon adoption of the amended NRG LTIP effective April 27, 2017, no shares of NRG common stock remain available for future issuance under the NRG GenOn LTIP as of December 31, 2017. There were 5,558,390 shares of NRG common stock authorized for issuance under the NRG GenOn LTIP as of December 31, 2016. As of December 31, 2017 and 2016, there were 1,369,880 and 960,904 shares of common stock remaining available for grants under the NRG GenOn LTIP, 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 2017, 2016 or 2015.

The following table summarizes the Company's NQSO activity and changes during the year:



	Shares^(a)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
					(In years)	(In millions)
Outstanding at December 31, 2016	1,522,919		$	25.03	3	$	—
Forfeited	(50,001	)	29.35
Exercised	(187,060	)	20.71
Outstanding at December 31, 2017	1,285,858		25.49		3	6
Exercisable at December 31, 2017	1,285,858		25.49		3	6

(a) As of December 31, 2017, 51,207 NQSOs granted to employees of GenOn remain outstanding and exercisable.

The following table summarizes the total intrinsic value of options exercised and the cash received from the exercises of options:



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Total intrinsic value of options exercised	$	1	$	—	$	2
Cash received from options exercised	4		—		9

There were no options exercised during the year ended December 31, 2016.

Restricted Stock Units

As of December 31, 2017, 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^(a)		Weighted Average Grant-Date Fair Value per Unit
Non-vested at December 31, 2016	1,980,141		$	19.29
Granted	1,247,075		12.44
Forfeited	(176,132	)	14.98
Vested	(673,271	)	23.65
Non-vested at December 31, 2017	2,377,813		14.63

(a) As of December 31, 2017, 20,822 RSUs granted to GenOn employees remain outstanding.

The total fair value of RSUs vested during the years ended December 31, 2017, 2016, and 2015, was $19 million, $11 million and $10 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2017, 2016, and 2015 was $12.44, $11.54, and $27.31, 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^(a)		Weighted Average Grant-Date Fair Value per Unit
Outstanding at December 31, 2016	453,674		$	21.54
Granted	120,251		16.76
Converted to Common Stock	(146,777	)	17.62
Outstanding at December 31, 2017	427,148		21.54

(a) There were no DSUs granted to GenOn employees and outstanding as of December 31, 2017.

The aggregate intrinsic values for DSUs outstanding as of December 31, 2017, 2016, and 2015 were approximately $12 million, $6 million, and $5 million, respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2017, 2016, and 2015 were $4 million, $1 million, and less than a million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2017, 2016, and 2015 was $16.76, $16.85 and $25.14, respectively.

Performance Stock Units

PSUs entitle the recipient to stock upon vesting. The amount of the award is subject to the Company's achievement of certain performance measures over the vesting period. As of December 31, 2017, non-vested PSUs consist of Market Stock Units, or MSUs, and Relative Performance Stock Units, or RPSUs.

Relative Performance Stock Units — RPSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's Total Shareholder Return, or TSR, relative to the TSR of the Company’s current proxy peer group and the total returns of select indexes, or Peer Group. Each RPSU 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 RPSU will depend on the Company’s percentile rank within the Peer Group. The number of shares of common stock to be paid as of the vesting date for each RPSU is linearly interpolated for TSR performance between the following points: (i) 0% if ranked below the 25th percentile; (ii) 25% if ranked at the 25th percentile; (iii) 100% if ranked at the 55th percentile (or the 65th percentile if the Company’s absolute TSR is less than negative 15%); and (iv) 200% if ranked at the 75th percentile or above. 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.

Market Stock Units — MSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's 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 common stock to be paid as of the vesting date for each MSU is : (i) zero shares, if the TSR has decreased by more than 25% over the performance period, (ii) three-quarters of one share, if the TSR has decreased by 25% over the performance period; (iii) interpolated between three-quarters of one share and one share, if the TSR has decreased less than 25% over the performance period; (iv) one share, if there is no change in TSR over the performance period; (v) interpolated between one share and two shares, if TSR increases less than 100% during the performance period; and (vi) two shares, if the TSR increases 100% over the performance period. 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 Company last granted MSUs during the year ended December 31, 2016.

The following table summarizes the Company's non-vested PSU awards and changes during the year:



	Units^(a)		Weighted Average Grant-Date Fair Value per Unit
Non-vested at December 31, 2016	1,282,588		$	21.47
Granted	738,830		15.91
Forfeited	(162,597	)	31.85
Non-vested at December 31, 2017	1,858,821		18.27

(a) There were no PSUs granted to GenOn employees and outstanding as of December 31, 2017.

The weighted average grant date fair value of PSUs granted during the years ended December 31, 2017, 2016 and 2015, was $15.91, $14.73 and $26.68, respectively.

The fair value of PSUs 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 PSUs are summarized below:



	2017		2016
	RPSUs		MSUs
Expected volatility	43.96	%	34.33	%
Expected term (in years)	3		3
Risk free rate	1.5	%	1.31	%

For the years ended December 31, 2017 and 2016, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the PSU, 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, 2017, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $5 million, $5 million, and $21 million for the years ended December 31, 2017, 2016, and 2015, 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	2017			2016			2015			2017		2017
	(In millions, except weighted average data)
NQSOs^(a)	$	—		$	—		$	—		$	—	—
RSUs	17			13			22			13		1.37
DSUs	2			2			2			—		—
MSUs	6			3			16			4		0.82
RPSUs	4			—			—			6		1.99
PRSUs^(b)	15			5			—			14		1.51
Total^(c)	$	44		$	23		$	40		$	37
Tax detriment recognized	$	(5	)	$	(4	)	$	(12	)

(a) All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2017, 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.

(c) Does not include GenOn compensation expense incurred prior to the deconsolidation of GenOn on June 14, 2017, of approximately $1 million for each of the years ended December 31, 2017, 2016, and 2015, which is recorded in loss from discontinued operations in the Company's consolidated statement of operations.

Related Party Transactions

12 Months Ended

Dec. 31, 2017

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,
	2017		2016		2015
	(In millions)
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	3	$	2	$	4
GenConn	5		5		4
Total	$	8	$	7	$	8

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 2010 and June 2011, respectively.

Services Agreement and Transition Services Agreement with GenOn

The Company provides GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn, or the Services Agreement. The initial term of the Services Agreement was through December 31, 2013, with an automatic renewal absent a request for termination. The fee charged was determined based on a fixed amount as described in the Services Agreement and was calculated based on historical GenOn expenses prior to the NRG Merger. The annual fees under the Services Agreement were approximately $193 million and management has concluded that this method of charging overhead costs is reasonable. As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, in connection with the Restructuring Support Agreement, NRG agreed to provide shared services to GenOn under the Services Agreement for an adjusted annualized fee of $84 million. Beginning on June 14, 2017, and through December 2017, NRG recorded amounts earned for shared services of approximately $5 million per month.

In December 2017, in conjunction with the confirmation of the GenOn Entities' plan of reorganization, the Services Agreement was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG will continue to provide the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments, until June 30, 2018, which may be extended by GenOn through September 30, 2018. NRG may provide additional separation services that are necessary for or reasonably related to the operation of GenOn's business after such date, subject to NRG's prior written consent, not to be unreasonably withheld. For the year ended December 31, 2017, NRG recorded other income - affiliate related to these services of $87 million prior to the Chapter 11 Filing and $42 million against selling, general and administrative expenses post-Chapter 11 Filing. For the year ended December 31, 2016, NRG recorded other income - affiliate related to these services of $193 million.

Also in December 2017, NRG provided GenOn with a $3.5 million credit for services provided under the transition services agreement and began recording amounts earned of approximately $7 million per month. NRG has also agreed to provide GenOn with a $28 million credit against amounts owed to NRG under the transition services agreement. The credit is intended to reimburse GenOn for its payment of financing costs. Any unused amount can be paid in cash at GenOn's request, subject to the terms and conditions of the transition services agreement.

See Note 3, Discontinued Operations, Acquisitions and Dispositions, for further discussion regarding the December 2017 agreed upon changes to the Restructuring Support Agreement and transition services agreement, based on which NRG recorded a reserve of $12 million against affiliate receivable balances as of December 31, 2017.

Credit Agreement with GenOn

NRG and GenOn are party to a secured intercompany revolving credit agreement. The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At December 31, 2017 and December 31, 2016, $92 million and $272 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of December 31, 2017, there were $125 million of loans outstanding under the intercompany secured revolving credit facility. As of December 31, 2016, no loans were outstanding under this intercompany secured revolving credit facility. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of December 31, 2017, GenOn was in default under the secured intercompany revolving credit agreement due to the filing of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, no additional revolving loans or letters of credit are available to GenOn. In addition, NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. The letter of credit facility provided availability of up to $330 million less amounts borrowed and letters of credit provided are required to be cash collateralized at 103% of the letter of credit amount. On July 27, 2017, this letter of credit facility was terminated as GenOn has obtained a separate letter of credit facility with a third party financial institution. Effective with completion of the reorganization, GenOn must repay NRG for all revolving loans outstanding, with such amount to be netted against the settlement payment owed from NRG to GenOn. Accordingly, the affiliate receivable is recorded net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of December 31, 2017. Interest continues to accrue during the pendency of the Chapter 11 Cases and borrowings remain secured obligations.

Commercial Operations Agreement

NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of December 31, 2017, derivative assets and liabilities associated with these transactions are recorded within NRG's derivative instruments balances on the consolidated balance sheet, with related revenues and costs within operating revenues and cost of operations, respectively. Additionally, as of December 31, 2017 and December 31, 2016, the Company had $32 million and $79 million, respectively, of cash collateral posted in support of energy risk management activities by GenOn.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

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. 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, 2017 are as follows:



Period	(In millions)
2018	$	1
2019	1
2020	1
2021	3
2022	6
Thereafter	228
Total	$	240

Other Operating Leases

NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2041. NRG also has certain tolling arrangements to purchase power, which 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 $81 million, $96 million, and $97 million for the years ended December 31, 2017, 2016, and 2015, respectively.

Future minimum lease commitments under operating leases for the years ending after December 31, 2017 are as follows:



Period	(In millions)
2018	$	78
2019	80
2020	75
2021	65
2022	64
Thereafter	479
Total ^(a)	$	841

(a) Amounts in the table exclude future sublease income of $49 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, 2017, 2016, and 2015, the Company purchased $1.2 billion, $1.2 billion, and $1.8 billion, respectively, under such arrangements.

As of December 31, 2017, the Company's commitments under such outstanding agreements are as follows:



Period	(In millions)
2018	$	527
2019	188
2020	150
2021	112
2022	103
Thereafter	296
Total	$	1,376

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, 2017. Minimum purchase commitment obligations are as follows as of December 31, 2017:



Period	(In millions)
2018	$	21
2019	14
2020	12
2021	11
2022	10
Thereafter	—
Total ^(a)	$	68


(a)	As of December 31, 2017, the maximum remaining term under any individual purchased power contract is five years.

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, 2017, hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.

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.

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.

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.

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. On August 28, 2017, the parties entered into an Assurance of Discontinuance resolving this matter.

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. 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. In February 2018, the parties agreed in principal to settle the matter. After the settlement agreement is signed by all parties (which the Company expects to occur in March 2018) and approved by the court, Midwest Generation will be required to (x) pay $500,000 to each of the State of Illinois and the Federal Government and (y) make and maintain certain operational improvements.

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 June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. Defendants filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to substitute new plaintiffs and on August 1, 2017, defendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should be stayed pending final court approval of the New Jersey settlement. On July 12, 2017, the parties in the New Jersey action reached an agreement in principle to resolve the class allegations which was confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in the New Jersey case filed their motion for preliminary approval of the class settlement which was approved by the court on November 17, 2017. On February 20, 2018 at the close of the objection deadline, two objections were filed to the Dobkin class settlement.

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 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 objections in response to the plaintiffs' complaint. The objections 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 objections to the amended complaints. On November 18, 2016, the court sustained the objections and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the objections without leave to amend. On July 14, 2017, CDWR filed a notice of appeal. On January 10, 2018, CDWR filed its appellate brief.

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. The Defendants filed objections and a motion challenging jurisdiction on October 18, 2016. On December 1, 2017, the parties agreed to a stipulation which provides the plaintiffs' opposition is due on March 6, 2018 and defendants' reply is due on May 4, 2018.

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. The defendants' reply was filed on March 24, 2017. The court heard oral argument on defendants' motion to dismiss on June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017. On December 11, 2017, the court dismissed the lawsuit with prejudice, thereby ending the case.

Griffoul v. NRG Residential Solar Solutions — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court. Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts. The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits. On June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June 29, 2017. On July 14, 2017, the court denied NRG's motion to compel arbitration or dismiss the case. On July 25, 2017, NRG filed a motion for reconsideration of the appeal, which the court denied. On August 22, 2017, NRG filed a notice of appeal. The appeal is fully briefed and scheduled for argument on April 24, 2018.

Rice v. NRG — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc. Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from GenOn's Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its answer and affirmative defenses.

Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against Louisiana Generating, L.L.C., or LaGen, in the United States District Court for the Middle District of Louisiana. The plaintiffs claim breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs seek damages for the alleged improper charges and a declaration as to which charges are proper under the contract. On September 14, 2017, the court issued a scheduling order setting this case for trial on October 21, 2019. LaGen filed a motion for a more definite statement on September 18, 2017 which the court denied on November 2, 2017. LaGen filed its answer and affirmative defenses on November 17, 2017.

GenOn Chapter 11 Cases — On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them supported the Bankruptcy Court's approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. If the plan of reorganization is not consummated, NRG may not be entitled to the benefits of the Settlement Agreement provided under the Restructuring Support Agreement and it will remain subject to any claims of GenOn and the noteholders, including claims relating to or arising out of any shared services and any other relationships or transactions between the companies. See Note 3, Discontinued Operations, Dispositions and Acquisitions, for additional information related to the Chapter 11 Cases.

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, LLC8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, 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 the Services Agreement between NRG and GenOn. Plaintiffs generally seek return 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. The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the Services Agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs, among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. On December 14, 2017, a settlement agreement was executed between GenOn and NRG which should ultimately resolve this lawsuit.

Morgantown v. GenOn Mid-Atlantic — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers on plaintiffs’ behalf. On November 7, 2017, the Bankruptcy Court issued an order estimating the claims to be valued at $0. On December 14, 2017, a settlement agreement was executed between GenOn and NRG which should ultimately resolve this lawsuit.

BTEC v. NRG Texas Power — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas Power LLC, or NRG Texas Power, in the Harris County District Court in Texas. On January 15, 2013, the parties entered into a Membership Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas. The MIPA required BTEC to meet a Guaranteed Commercial Completion Date of May 31, 2016. But even a year later, BTEC had not satisfied all of the contractually-required acceptance criteria. As a result and given that the MIPA expiration date passed on May 31, 2017, NRG elected to terminate the contract in June 2017. BTEC claims that NRG Texas Power breached the MIPA by improperly terminating it, and seeks a declaratory judgment as to the rights and obligations of the parties. In addition, BTEC seeks damages, interest and attorney’s fees. On August 14, 2017, NRG Texas Power served its answer to the lawsuit. On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million.

GenOn Related Contingencies

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. On June 1, 2017, the Fifth Circuit affirmed the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. The bankruptcy court is scheduled to hear a Motion for a Final Decree in the Mirant bankruptcy on April 11, 2018.

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, or 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 Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. 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 U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. 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 March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the Ninth Circuit for interlocutory review of the court’s order denying class certification. On June 13, 2017, the Ninth Circuit granted plaintiffs' petition for interlocutory review. On November 22, 2017, plaintiffs filed their appellate brief. On January 22, 2018, the defendants filed their opposition brief.

In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. The appeal has been fully briefed by the parties and was argued on February 16, 2018. 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 U.S. Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits.

Potomac River Environmental Investigation — In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, 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 Potomac River LLC is currently reviewing the information provided by DOEE.

Natixis v. GenOn Mid-Atlantic — On February 16, 2018, Natixis Funding Corp. and Natixis, New York Branch filed a complaint in the Supreme Court of the State of New York against GenOn Mid-Atlantic, the owner lessors under GenOn Mid-Atlantic’s operating leases of the Dickerson and Morgantown coal generation units, and the lease indenture trustee under those leases. The plaintiffs’ allegations against GenOn Mid-Atlantic relate to a payment agreement between GenOn Mid-Atlantic and Natixis Funding Corp. to procure credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. Plaintiffs seek approximately $34 million in damages arising from GenOn Mid-Atlantic’s purported breach of certain warranties in the payment agreement.

Regulatory Matters	12 Months Ended
Regulatory Matters	Dec. 31, 2017
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 in Illinois — In 2016, Illinois enacted a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to nuclear plants in Illinois that would otherwise retire. Pursuant to the legislation, the Illinois Power Agency, or IPA, conducts a competitive solicitation to procure ZECs, although both the Governor of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-owned nuclear power plants in Illinois. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. Another plaintiff group filed a similar complaint on the same day. Subsequently, on March 31, 2017, NRG, along with other companies, filed a motion for preliminary injunction. On April 10, 2017, Exelon, as an intervenor defendant, and State defendants filed motions to dismiss. On July 14, 2017, Defendants' motions to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Seventh Circuit. Briefing is complete. Oral argument was held on January 3, 2018, with supplemental briefs filed on January 26, 2018. On February 21, 2018, the Seventh Circuit invited the U.S. to file an amicus brief in the proceeding. Zero-Emission Credits for Nuclear Plants 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. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On October 19, 2016, NRG, along with other companies, filed a complaint in the U.S. District Court for the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. On March 29, 2017, the U.S. District Court heard oral arguments on a motion to dismiss filed by defendants. On July 25, 2017, the defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other plaintiff companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. Briefing is complete. Oral argument has been noticed for March 12, 2018. Department of Energy's Proposed Grid Resiliency Pricing Rule — On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new rulemaking asking each ISO/RTO to address specific questions focused on grid resilience. East/West 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. On February 1, 2018, the court heard oral arguments. California Station Power — As the result of unfavorable final and non-appealable litigation, the Company has accrued a liability associated with consumption of station power at three of the Company’s power plants in California, after August 30, 2010. In December 2017, subsidiaries of the Company entered into settlements with SCE for the liabilities associated with the Company's El Segundo and Long Beach facilities. The Company has established an appropriate reserve pending potential regulatory action by SDG&E regarding Encina. Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017. During the six month suspension period, which could conceivably be extended, NRG will evaluate the progress of a procurement process initiated by SCE to replace the Puente Power Project.

Environmental Matters (Notes)	12 Months Ended
Environmental Matters (Notes)	Dec. 31, 2017
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 has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed. 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 slow or pause in the near term with respect to federal laws under the current 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 NO_x 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 NO_x 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. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. 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. Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, or FGD, fly ash, bottom ash, and flue gas mercury control. In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking and (ii) withdrew the April 2017 administrative stay. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company has largely eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised. 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. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities Group filed in May 2017. 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, 2017. East/West Region New Source Review — The EPA and various states have been 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 litigation described in Item 15 — Note 22, Commitments and Contingencies. 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 generating 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, the Company's Closure Report and the Company's Long Term Stewardship Plan. In the second quarter of 2017, the Company completed the remediation requirements in the remediation plan. The cost of completing the work required by the remediation plan was within amounts budgeted in early 2016 and remediation was completed 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)

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Cash Flow Information

Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Interest paid, net of amount capitalized	$	868	$	890	$	924
Income taxes paid ^(a)	9		14		12
Non-cash investing and financing activities:
Additions/(decrease) to fixed assets for accrued capital expenditures	70		35		(44		)

(a) In 2017, income taxes paid of $11 million are offset by $2 million in income tax refunds. In 2015, income taxes paid of $13 million are offset by $1 million in income tax refunds.

Guarantees

12 Months Ended

Dec. 31, 2017

Guarantees [Abstract]

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. In some cases, NRG's maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential 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,
	2017
Guarantees	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2016 Total
	(In millions)
Letters of credit and surety bonds^(a)	$	1,467	$	66	$	7	$	93	$	1,633	$	1,837
Asset sales guarantee obligations	—		—		257		55		312		677
Other guarantees	—		32		—		613		645		253
Total guarantees	$	1,467	$	98	$	264	$	761	$	2,590	$	2,767


(a)	Excludes$92 million and $272 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn as of December 31, 2017 and 2016, respectively.

Letters of credit and surety bonds — As of December 31, 2017, NRG and its consolidated subsidiaries were contingently obligated for a total of $1.6 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)

12 Months Ended

Dec. 31, 2017

Jointly Owned Plants Disclosure [Abstract]

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, 2017	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	%	$	395	$	(207	)	$	7
Big Cajun II Unit 3, New Roads, LA	58.00	%	202		(132		)	—
Cedar Bayou Unit 4, Baytown, TX	50.00	%	215		(75		)	7
Keystone, Shelocta, PA	3.70	%	12		—			1
Conemaugh, New Florence, PA	3.72	%	14		—			1

Unaudited Quarterly Financial Data

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Unaudited Quarterly Financial Data

Refer to Note 3, Discontinued Operations, 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
	2017
	December 31			September 30			June 30			March 31
	(In millions, except per share data)
Operating revenues	$	2,497		$	3,049		$	2,701		$	2,382
Operating (loss)/ income	(1,345		)	376			343			39
Net (loss)/income from continuing operations	(1,667		)	190			99			(170		)
Income/(loss) from discontinued operations	13			(27		)	(741		)	(34		)
Net (loss)/income	(1,655		)	163			(642		)	(203		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(120		)	(8		)	(16		)	(40		)
Net (loss)/income attributable to NRG Energy, Inc.	(1,535		)	171			(626		)	(163		)
(Loss)/income available to Common Stockholders	$	(1,535	)	$	171		$	(626	)	$	(163	)
Weighted average number of common shares outstanding — basic	317			317			316			316
Income/(loss) from discontinued operations per weighted average common share — basic	$	0.04		$	(0.09	)	$	(2.34	)	$	(0.11	)
Net (loss)/income per weighted average common share — basic	$	(4.84	)	$	0.54		$	(1.98	)	$	(0.52	)
Weighted average number of common shares outstanding — diluted	317			322			316			316
Income/(loss) from discontinued operations per weighted average common share — diluted	$	0.04		$	(0.08	)	$	(2.34	)	$	(0.11	)
Net (loss)/income per weighted average common share — diluted	$	(4.84	)	$	0.53		$	(1.98	)	$	(0.52	)



	Quarter Ended
	2016
	December 31				September 30				June 30				March 31
	(In millions, except per share data)
Operating revenues	$	2,184			$	3,421			$	2,248			$	2,659
Operating (loss)/income	(658		)	—	429			—	164				331
Net (loss)/income from continuing operations	(891		)		128				(163		)		(57		)
(Loss)/income from discontinued operations	(164		)		265				(113		)		104
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
(Loss)/income from discontinued operations per weighted average common share — basic	$	(0.52	)		$	0.84			$	(0.36	)		$	0.33
Net (loss)/income per weighted average common share — basic	$	(3.12	)		$	1.27			$	(0.61	)		$	0.24
Weighted average number of common shares outstanding — diluted	316				317				315				315
(Loss)/income from discontinued operations per weighted average common share — diluted	$	(0.52	)		$	0.84			$	(0.36	)		$	0.33
Net (loss)/income per weighted average common share — diluted	$	(3.12	)	—	$	1.27		—	$	(0.61	)	—	$	0.24

Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Consolidating Financial Information

As of December 31, 2017, the Company had outstanding $4.8 billion of Senior Notes due 2022 - 2028, 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, 2017:



Ace Energy, Inc.	New Genco GP, LLC	NRG Norwalk Harbor Operations Inc.
Allied Home Warranty GP LLC	Norwalk Power LLC	NRG Operating Services, Inc.
Allied Warranty LLC	NRG Advisory Services LLC	NRG Oswego Harbor Power Operations Inc.
Arthur Kill Power LLC	NRG Affiliate Services Inc.	NRG PacGen Inc.
Astoria Gas Turbine Power LLC	NRG Arthur Kill Operations Inc.	NRG Portable Power LLC
Bayou Cove Peaking Power, LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Power Marketing LLC
BidURenergy, Inc.	NRG Bayou Cove LLC	NRG Reliability Solutions LLC
Cabrillo Power I LLC	NRG Business Services LLC	NRG Renter's Protection LLC
Cabrillo Power II LLC	NRG Cabrillo Power Operations Inc.	NRG Retail LLC
Carbon Management Solutions LLC	NRG California Peaker Operations LLC	NRG Retail Northeast LLC
Cirro Group, Inc.	NRG Cedar Bayou Development Company, LLC	NRG Rockford Acquisition LLC
Cirro Energy Services, Inc.	NRG Connected Home LLC	NRG Saguaro Operations Inc.
Conemaugh Power LLC	NRG Connecticut Affiliate Services Inc.	NRG Security LLC
Connecticut Jet Power LLC	NRG Construction LLC	NRG Services Corporation
Cottonwood Development LLC	NRG Curtailment Solutions, Inc	NRG SimplySmart Solutions LLC
Cottonwood Energy Company LP	NRG Development Company Inc.	NRG South Central Affiliate Services Inc.
Cottonwood Generating Partners I LLC	NRG Devon Operations Inc.	NRG South Central Generating LLC
Cottonwood Generating Partners II LLC	NRG Dispatch Services LLC	NRG South Central Operations Inc.
Cottonwood Generating Partners III LLC	NRG Distributed Energy Resources Holdings LLC	NRG South Texas LP
Cottonwood Technology Partners LP	NRG Distributed Generation PR LLC	NRG SPV #1 LLC
Devon Power LLC	NRG Dunkirk Operations Inc.	NRG Texas C&I Supply LLC
Dunkirk Power LLC	NRG El Segundo Operations Inc.	NRG Texas Gregory LLC
Eastern Sierra Energy Company LLC	NRG Energy Efficiency-L LLC	NRG Texas Holding Inc.
El Segundo Power, LLC	NRG Energy Labor Services LLC	NRG Texas LLC
El Segundo Power II LLC	NRG ECOKAP Holdings LLC	NRG Texas Power LLC
Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Warranty Services LLC
Energy Choice Solutions LLC	NRG Energy Services International Inc.	NRG West Coast LLC
Energy Plus Holdings LLC	NRG Energy Services LLC	NRG Western Affiliate Services Inc.
Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	O'Brien Cogeneration, Inc. II
Energy Protection Insurance Company	NRG Greenco LLC	ONSITE Energy, Inc.
Everything Energy LLC	NRG Home & Business Solutions LLC	Oswego Harbor Power LLC
Forward Home Security, LLC	NRG Home Services LLC	Reliant Energy Northeast LLC
GCP Funding Company, LLC	NRG Home Solutions LLC	Reliant Energy Power Supply, LLC
Green Mountain Energy Company	NRG Home Solutions Product LLC	Reliant Energy Retail Holdings, LLC
Gregory Partners, LLC	NRG Homer City Services LLC	Reliant Energy Retail Services, LLC
Gregory Power Partners LLC	NRG Huntley Operations Inc.	RERH Holdings, LLC
Huntley Power LLC	NRG HQ DG LLC	Saguaro Power LLC
Independence Energy Alliance LLC	NRG Identity Protect LLC	Somerset Operations Inc.
Independence Energy Group LLC	NRG Ilion Limited Partnership	Somerset Power LLC
Independence Energy Natural Gas LLC	NRG Ilion LP LLC	Texas Genco GP, LLC
Indian River Operations Inc.	NRG International LLC	Texas Genco Holdings, Inc.
Indian River Power LLC	NRG Maintenance Services LLC	Texas Genco LP, LLC
Keystone Power LLC	NRG Mextrans Inc.	Texas Genco Services, LP
Langford Wind Power, LLC	NRG MidAtlantic Affiliate Services Inc.	US Retailers LLC
Louisiana Generating LLC	NRG Middletown Operations Inc.	Vienna Operations Inc.
Meriden Gas Turbines LLC	NRG Montville Operations Inc.	Vienna Power LLC
Middletown Power LLC	NRG New Roads Holdings LLC	WCP (Generation) Holdings LLC
Montville Power LLC	NRG North Central Operations Inc.	West Coast Power LLC
NEO Corporation	NRG Northeast Affiliate Services Inc.

The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic 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 SEC'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, 2017



	Guarantor Subsidiaries				Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,182		—	$	3,699		—	$	—		$	(252	)	$	10,629
Operating Costs and Expenses
Cost of operations	5,373				2,353				59			(249		)	7,536
Depreciation and amortization	405				619				32			—			1,056
Impairment losses	1,463				246				—			—			1,709
Selling, general and administrative	371				146				393			(3		)	907
Reorganization costs	6				—				38			—			44
Development costs	—				49				18			—			67
Total operating costs and expenses	7,618				3,413				540			(252		)	11,319
Other income - affiliate	—				—				87			—			87
Gain on sale of assets	4				12				—			—			16
Operating (Loss)/Income	(432		)		298				(453		)	—			(587		)
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries	(1,162		)		(113		)		26			1,249			—
Equity in earnings/(losses) of unconsolidated affiliates	—				95				(4		)	(60		)	31
Impairment losses on investments	—				(75		)		(4		)	—			(79		)
Other income, net	9				17				12			—			38
Net loss on debt extinguishment	—				(4		)		(49		)	—			(53		)
Interest expense	(14		)		(424		)		(452		)	—			(890		)
Total other expense	(1,167		)		(504		)		(471		)	1,189			(953		)
Loss from Continuing Operations Before Income Taxes	(1,599		)		(206		)		(924		)	1,189			(1,540		)
Income tax (benefit)/expense	(598		)		(10		)		616			—			8
Loss from Continuing Operations	(1,001		)		(196		)		(1,540		)	1,189			(1,548		)
Loss from Discontinued Operations, net of income tax	—				(160		)		(629		)	—			(789		)
Net Loss	(1,001		)		(356		)		(2,169		)	1,189			(2,337		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	—				(108		)		(16		)	(60		)	(184		)
Net Loss Attributable to NRG Energy, Inc.	$	(1,001	)		$	(248	)		$	(2,153	)	$	1,249		$	(2,153	)


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

For the Year Ended December 31, 2017



	Guarantor Subsidiaries				Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)				Eliminations^(a)			Consolidated Balance
	(In millions)
Net Loss	$	(1,001	)		$	(356	)		$	(2,169	)		$	1,189		$	(2,337	)
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain on derivatives, net	1				13				25				(26		)	13
Foreign currency translation adjustments, net	6				7				—				(1		)	12
Available-for-sale securities, net	—				—				(8		)		—			(8		)
Defined benefit plan, net	(24		)		29				41				—			46
Other comprehensive (loss)/income	(17		)		49				58				(27		)	63
Comprehensive Loss	(1,018		)		(307		)		(2,111		)		1,162			(2,274		)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			—	(103		)	—	(16		)	—	(60		)	(179		)
Comprehensive Loss Attributable to NRG Energy, Inc.	$	(1,018	)		$	(204	)		$	(2,095	)		$	1,222		$	(2,095	)


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2017



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries				NRG Energy, Inc.				Eliminations^(a)			Consolidated Balance
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	—		$	348			$	643			$	—		$	991
Funds deposited by counterparties	37			—				—				—			37
Restricted cash	4			504				—				—			508
Accounts receivable - trade	769			306				4				—			1,079
Inventory	339			193				—				—			532
Derivative instruments	625			80				9				(88		)	626
Cash collateral posted in support of energy risk management activities	170			1				—				—			171
Accounts receivable - affiliate	712			210				(129		)		(698		)	95
Current assets held-for-sale	8			107				—				—			115
Prepayments and other current assets	116			118				27				—			261
Total current assets	2,780			1,867				554				(786		)	4,415
Net Property, Plant and Equipment	2,527			11,169			—	238			—	(26		)	13,908
Other Assets
Investment in subsidiaries	(106		)	28			—	7,581				(7,503		)	—
Equity investments in affiliates	—			1,036				2				—			1,038
Notes receivable, less current portion	—			2				36				(36		)	2
Goodwill	360			179				—				—			539
Intangible assets, net	458			1,291				—				(3		)	1,746
Nuclear decommissioning trust fund	692			—				—				—			692
Deferred income taxes	377			(7		)		(236		)		—			134
Derivative instruments	121			40				31				(20		)	172
Non-current assets held-for-sale	—			43				—				—			43
Other non-current assets	51			458				120				—			629
Total other assets	1,953			3,070				7,534				(7,562		)	4,995
Total Assets	$	7,260		$	16,106			$	8,326			$	(8,374	)	$	23,318
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	667			$	57			$	(36	)	$	688
Accounts payable	546			280				55				—			881
Accounts payable - affiliate	752			(202		)		181				(698		)	33
Derivative instruments	535			108				—				(88		)	555
Cash collateral received in support of energy risk management activities	37			—				—				—			37
Accrued interest expense	3			56				97				—			156
Current liabilities - held-for-sale	—			72				—				—			72
Other accrued expenses and other current liabilities	288			118				328				—			734
Other accrued expenses and other current liabilities - affiliate	—			—				161				—			161
Total current liabilities	2,161			1,099				879				(822		)	3,317
Other Liabilities
Long-term debt and capital leases	244			8,733				6,739				—			15,716
Nuclear decommissioning reserve	269			—				—				—			269
Nuclear decommissioning trust liability	415			—				—				—			415
Postretirement and other benefit obligations	118			1				339				—			458
Deferred income taxes	112			64				(155		)		—			21
Derivative instruments	110			107				—				(20		)	197
Out-of-market contracts, net	66			141				—				—			207
Non-current liabilities held-for-sale	—			8				—				—			8
Other non-current liabilities	295			317				52				—			664
Total non-current liabilities	1,629			9,371				6,975				(20		)	17,955
Total Liabilities	3,790			10,470				7,854				(842		)	21,272
Redeemable noncontrolling interest in subsidiaries	—			78				—				—			78
Stockholders' Equity	3,470			5,558				472				(7,532		)	1,968
Total Liabilities and Stockholders' Equity	$	7,260		$	16,106			$	8,326			$	(8,374	)	$	23,318


(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, 2017



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance

Cash Flows from Operating Activities
Net loss	$	(1,001	)	$	(356	)	$	(2,169	)	$	1,189		$	(2,337	)
Loss from discontinued operations	—			(160		)	(629		)	—			(789		)
Net loss from continuing operations	(1,001		)	(196		)	(1,540		)	1,189			(1,548		)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in earnings and distributions from unconsolidated affiliates	—			5			4			46			55
Depreciation and amortization	405			619			32			—			1,056
Provision for bad debts	54			2			12			—			68
Amortization of nuclear fuel	51			—			—			—			51
Amortization of financing costs and debt discount/premiums	—			42			18			—			60
Adjustment for debt extinguishment	—			4			49			—			53
Amortization of intangibles and out-of-market contracts	27			81			—			—			108
Amortization of unearned equity compensation	—			—			35			—			35
Net gain on sale of assets and equity method investments	(18		)	(16		)	—			—			(34		)
Impairment losses	1,463			321			4			—			1,788
Changes in derivative instruments	(100		)	(69		)	24			(26		)	(171		)
Changes in deferred income taxes and liability for uncertain tax benefits	(300		)	69			322			—			91
Changes in collateral deposits in support of energy risk management activities	(98		)	18			—			—			(80		)
Proceeds from sale of emission allowances	25			—			—			—			25
Changes in nuclear decommissioning trust liability	11			—			—			—			11
Cash (used)/provided by changes in other working capital	(363		)	(164		)	1,593			(1,209		)	(143		)
Cash provided by continuing operations	156			716			553			—			1,425
Cash used by discontinued operations	—			(38		)	—			—			(38		)
Net Cash Provided by Operating Activities	156			678			553			—			1,387
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			94			(94		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(249		)	—			249			—
Intercompany dividends	—			—			129			(129		)	—
Acquisition of businesses, net of cash acquired	(14		)	(27		)	—			—			(41		)
Capital expenditures	(183		)	(906		)	(22		)	—			(1,111		)
Net cash proceeds from notes receivable	—			17			—			—			17
Proceeds from renewable energy grants	8			—			—			—			8
Proceeds from sale of emission allowances	66			—			—			—			66
Investments in nuclear decommissioning trust fund securities	(512		)	—			—			—			(512		)
Proceeds from sales of nuclear decommissioning trust fund securities	501			—			—			—			501
Proceeds from sale of assets, net	33			54			—			—			87
Investments in unconsolidated affiliates	—			(40		)	—			—			(40		)
Other	18			(6		)	—			—			12
Cash (used)/provided by continuing operations	(83		)	(1,157		)	201			26			(1,013		)
Cash used by discontinued operations	—			(53		)	—			—			(53		)
Net Cash (Used)/Provided by Investing Activities	(83		)	(1,210		)	201			26			(1,066		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(94		)	—			94			—
Payments from/(for) intercompany loans	(45		)	13			32			—			—
Acquisition of Drop Down Assets, net of cash acquired	—			—			249			(249		)	—
Intercompany dividends	—			(129		)	—			129			—
Payment of dividends to common and preferred stockholders	—			—			(38		)	—			(38		)
Net receipts from settlement of acquired derivatives that include financing elements	—			2			—			—			2
Payments for debt extinguishment costs	—			—			(42		)	—			(42		)
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—			95			—			—			95
Payments from issuance of common stock	—			—			(2		)	—			(2		)
Proceeds from issuance of long-term debt	—			1,186			1,084			—			2,270
Payment of debt issuance and hedging costs	—			(47		)	(16		)	—			(63		)
Payments for short and long-term debt	—			(647		)	(1,701		)	—			(2,348		)
Receivable from affiliate	—			(125		)	—			—			(125		)
Other	—			(10		)	—			—			(10		)
Cash provided/(used) by continuing operations	(45		)	244			(434		)	(26		)	(261		)
Cash used by discontinued operations	—			(224		)	—			—			(224		)
Net Cash Provided/(Used) by Financing Activities	(45		)	20			(434		)	(26		)	(485		)
Effect of exchange rate changes on cash and cash equivalents	—			(1		)	—			—			(1		)
Change in cash from discontinued operations	—			(315		)	—			—			(315		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	28			(198		)	320			—			150
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	13			1,050			323			—			1,386
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	41		$	852		$	643		$	—		$	1,536


(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, 2016



	Guarantor Subsidiaries				Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,509		—	$	3,222		—	$	—		$	(219	)	$	10,512
Operating Costs and Expenses
Cost of operations	5,402				2,080				42			(223		)	7,301
Depreciation and amortization	565				581				26			—			1,172
Impairment losses	378				324				—			—			702
Selling, general and administrative	415				192				488			—			1,095
Development costs	—				59				30			—			89
Total operating costs and expenses	6,760				3,236				586			(223		)	10,359
Other income - affiliate	—				—				193			—			193
Loss on sale of assets	(1		)		—				(79		)	—			(80		)
Operating Income/(Loss)	748				(14		)		(472		)	4			266
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries	(176		)		(5		)		313			(132		)	—
Equity in earnings/(losses) of unconsolidated affiliates	5				36				(4		)	(10		)	27
Impairment losses on investments	—				(252		)		(16		)	—			(268		)
Other income, net	4				23				9			(2		)	34
Net loss on debt extinguishment	—				(4		)		(138		)	—			(142		)
Interest expense	(15		)		(396		)		(484		)	—			(895		)
Total other expense	(182		)		(598		)		(320		)	(144		)	(1,244		)
Income/(Loss) from Continuing Operations Before Income Taxes	566				(612		)		(792		)	(140		)	(978		)
Income tax (benefit)/expense	(1		)		7				(63		)	62			5
Income/(Loss) from Continuing Operations	567				(619		)		(729		)	(202		)	(983		)
Income from Discontinued Operations, net of income tax	—				81				11			—			92
Net Income/(Loss)	567				(538		)		(718		)	(202		)	(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.	$	567			$	(435	)		$	(774	)	$	(132	)	$	(774	)


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

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)	$	567		$	(538	)		$	(718	)		$	(202	)	$	(891	)
Other Comprehensive Income, 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	34			(13		)		(51		)		33			3
Other comprehensive income	33			18				38				(51		)	38
Comprehensive Income/(Loss)	600			(520		)		(680		)		(253		)	(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.	600			(417		)	—	(736		)		(183		)	(736		)
Dividends for preferred shares	—			—				5			—	—			5
Gain on redemption of preferred shares	—			—				(78		)		—			(78		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	600		$	(417	)		$	(663	)		$	(183	)	$	(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

ASSETS
Current Assets
Cash and cash equivalents	$	—		$	615			$	323			$	—		$	938
Funds deposited by counterparties	2			—				—				—			2
Restricted cash	11			435				—				—			446
Accounts receivable - trade	734			321				3				—			1,058
Inventory	482			239				—				—			721
Derivative instruments	962			196				1				(92		)	1,067
Cash collateral posted in support of energy risk management activities	116			34				—				—			150
Accounts receivable - affiliate	307			(254		)		200				(139		)	114
Current assets held-for-sale	—			9				—				—			9
Prepayments and other current assets	76			152				62				—			290
Current assets - discontinued operations	—			1,919				—				—			1,919
Total current assets	2,690			3,666				589				(231		)	6,714
Net Property, Plant and Equipment	4,219			10,926				251				(27		)	15,369
Other Assets
Investment in subsidiaries	1,090			145				10,128				(11,363		)	—
Equity investments in affiliates	(13		)	1,103				30				—			1,120
Notes receivable, less current portion	—			16				(76		)		76			16
Goodwill	359			303				—				—			662
Intangible assets, net	592			1,384				—				(3		)	1,973
Nuclear decommissioning trust fund	610			—				—				—			610
Derivative instruments	144			44				36				(43		)	181
Deferred income taxes	3			—				222				—			225
Non-current assets held for sale	—			10				—				—			10
Other non-current assets	67			446				328				—			841
Non-current assets - discontinued operations	—			2,961				—				—			2,961
Total other assets	2,852			6,412				10,668				(11,333		)	8,599
Total Assets	$	9,761		$	21,004			$	11,508			$	(11,591	)	$	30,682
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	498			$	(58	)		$	76		$	516
Accounts payable	501			247				34				—			782
Accounts payable - affiliate	753			(443		)		(200		)		(79		)	31
Derivative instruments	947			237				—				(92		)	1,092
Cash collateral received in support of energy risk management activities	81			—				—				—			81
Accrued interest expense	3			54				123				—			180
Other accrued expenses and other current liabilities	313			155				342				—			810
Current liabilities - discontinued operations	—			1,210				—				—			1,210
Total current liabilities	2,598			1,958				241				(95		)	4,702
Other Liabilities
Long-term debt and capital leases	244			8,252				7,461				—			15,957
Nuclear decommissioning reserve	287			—				—				—			287
Nuclear decommissioning trust liability	339			—				—				—			339
Postretirement and other benefit obligations	113			122				275				—			510
Deferred income taxes	186			125				(291		)		—			20
Derivative instruments	157			170				—				(43		)	284
Out-of-market contracts, net	80			150				—				—			230
Non-current liabilities held-for-sale	—			11				—				—			11
Other non-current liabilities	283			309				74				—			666
Other non-current liabilities - discontinued operations	—			3,184				—				—			3,184
Total non-current liabilities	1,689			12,323				7,519				(43		)	21,488
Total Liabilities	4,287			14,281				7,760				(138		)	26,190
Redeemable noncontrolling interest in subsidiaries	—			46				—				—			46
Stockholders' Equity	5,474			6,677			—	3,748			—	(11,453		)	4,446
Total Liabilities and Stockholders' Equity	$	9,761		$	21,004			$	11,508			$	(11,591	)	$	30,682


(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)	$	567		$	(538	)	$	(718	)	$	(202	)	$	(891	)
Income from discontinued operations	—			81			11			—			92
Net income/(loss) from continuing operations	567			(619		)	(729		)	(202		)	(983		)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distribution of unconsolidated affiliates	(5		)	52			5			2			54
Depreciation and amortization	565			581			26			—			1,172
Provision for bad debts	41			7			—			—			48
Amortization of nuclear fuel	49			—			—			—			49
Amortization of financing costs and debt discount/premiums	—			34			21			—			55
Adjustment for debt extinguishment	—			4			138			—			142
Amortization of intangibles and out-of-market contracts	39			128			—			—			167
Amortization of unearned equity compensation	—			—			10			—			10
Net loss on sale of assets and equity method investments, net	—			—			70			—			70
Impairment losses	378			578			16			—			972
Changes in derivative instruments	(77		)	145			(36		)	—			32
Changes in deferred income taxes and liability for uncertain tax benefits	(1		)	18			(60		)	—			(43		)
Changes in collateral deposits in support of energy risk management activities	437			(39		)	—			—			398
Proceeds from sale of emission allowances	34			—			—			—			34
Changes in nuclear decommissioning trust liability	41			—			—			—			41
Cash (used)/provided by changes in other working capital	(1,815		)	417			1,187			200			(11		)
Cash provided by continuing operations	253			1,306			648			—			2,207
Cash used by discontinued operations	—			(119		)	—			—			(119		)
Net Cash Provided by Operating Activities	253			1,187			648			—			2,088
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			81			(81		)	—
Intercompany dividends	—			—			12			(12		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(77		)	—			77			—
Acquisition of businesses, net of cash acquired	—			(209		)	—			—			(209		)
Capital expenditures	(180		)	(748		)	(48		)	—			(976		)
Net cash proceeds from 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 fund securities	(551		)	—			—			—			(551		)
Proceeds from sales of nuclear decommissioning trust fund securities	510			—			—			—			510
Proceeds from sale of assets, net	—			56			17			—			73
Investments in unconsolidated affiliates	3			(26		)	—			—			(23		)
Other	27			—			8			—			35
Cash (used)/provided by continuing operations	(192		)	(951		)	70			(16		)	(1,089		)
Cash provided by discontinued operations	—			297			—			—			297
Net Cash (Used)/Provided by Investing Activities	(192		)	(654		)	70			(16		)	(792		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(81		)	—			81			—
Intercompany dividends	(52		)	40			—			12			—
Payments (for)/from intercompany loans	(52		)	(49		)	101			—			—
Acquisition of Drop Down Assets, net of cash acquired	—			—			77			(77		)	—
Payment of dividends to common and preferred stockholders	—			—			(76		)	—			(76		)
Net receipts from settlement of acquired derivatives that include financing elements	—			6			—			—			6
Payment for preferred shares	—			—			(226		)	—			(226		)
Payments for debt extinguishment costs	—			—			(121		)	—			(121		)
Distributions from, net of contributions to, noncontrolling interest 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
Payment of debt issuance and hedging costs	—			(29		)	(60		)	—			(89		)
Payments for short and long-term debt	(1		)	(983		)	(4,924		)	—			(5,908		)
Other	(3		)	(10		)	—			—			(13		)
Cash (used)/provided by continuing operations	(108		)	125			(1,088		)	16			(1,055		)
Cash provided by discontinued operations	—			140			—			—			140
Net Cash (Used)/Provided by Financing Activities	(108		)	265			(1,088		)	16			(915		)
Effect of exchange rate changes on cash and cash equivalents	—			1			—			—			1
Change in cash from discontinued operations	—			318			—			—			318
Net (Decrease)/Increase in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	(47		)	481			(370		)	—			64
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	60			569			693			—			1,322
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	13		$	1,050		$	323		$	—		$	1,386

(a) All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2015



	Guarantor Subsidiaries				Non-Guarantor Subsidiaries				NRG Energy, Inc.			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	9,881		—	$	2,541		—	$	—		$	(94	)	$	12,328
Operating Costs and Expenses
Cost of operations	7,610				1,470				14			(94		)	9,000
Depreciation and amortization	751				580				20			—			1,351
Impairment losses	4,494				366				—			—			4,860
Selling, general and administrative	468				204				556			—			1,228
Development costs	—				61				93			—			154
Total operating costs and expenses	13,323				2,681				683			(94		)	16,593
Other income - affiliate	—				—				193			—			193
Gain on postretirement benefits curtailment	—				21				—			—			21
Operating Loss	(3,442		)		(119		)		(490		)	—			(4,051		)
Other (Expense)/Income
Equity in losses of consolidated subsidiaries	(109		)		(1		)		(2,800		)	2,910			—
Equity in earnings of unconsolidated affiliates	8				37				—			(9		)	36
Impairment losses on investments	—				(25		)		(31		)	—			(56		)
Other income, net	4				21				1			—			26
Loss on sale of equity-method investment	—				—				(14		)	—			(14		)
Net (loss)/gain on debt extinguishment	—				(9		)		19			—			10
Interest expense	(14		)		(366		)		(557		)	—			(937		)
Total other expense	(111		)		(343		)		(3,382		)	2,901			(935		)
Loss from Continuing Operations Before Income Taxes	(3,553		)		(462		)		(3,872		)	2,901			(4,986		)
Income tax (benefit)/expense	(1,104		)		(93		)		2,489			53			1,345
Loss from Continuing Operations	(2,449		)		(369		)		(6,361		)	2,848			(6,331		)
Loss/(income) from Discontinued Operations, net of income tax	—				(115		)		10			—			(105		)
Net Loss	(2,449		)		(484		)		(6,351		)	2,848			(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.	$	(2,449	)		$	(461	)		$	(6,382	)	$	2,910		$	(6,382	)


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

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	$	(2,449	)	$	(484	)	$	(6,351	)	$	2,848		$	(6,436	)
Other Comprehensive (Loss)/Income, net of tax
Unrealized (loss)/gain on derivatives, net	(8		)	(16		)	48			(39		)	(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	(30		)	(39		)	20			50			1
Comprehensive Loss	(2,479		)	(523		)	(6,331		)	2,898			(6,435		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest	—			(42		)	31			(62		)	(73		)
Comprehensive Loss Attributable to NRG Energy, Inc.	(2,479		)	(481		)	(6,362		)	2,960			(6,362		)
Dividends for preferred shares	—			—			20			—			20
Comprehensive Loss Available for Common Stockholders	$	(2,479	)	$	(481	)	$	(6,382	)	$	2,960		$	(6,382	)


(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. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net loss	$	(2,449	)	$	(484	)	$	(6,351	)	$	2,848		$	(6,436	)
(Loss)/income from discontinued operations	—			(115		)	10			—			(105		)
Net loss from continuing operations	(2,449		)	(369		)	(6,361		)	2,848			(6,331		)
Adjustments to reconcile net loss to net cash (used)/provided by operating activities:
Equity in earnings and distribution of unconsolidated affiliates	(5		)	54			—			(12		)	37
Depreciation and amortization	751			580			20			—			1,351
Provision for bad debts	58			3			3			—			64
Amortization of nuclear fuel	45			—			—			—			45
Amortization of financing costs and debt discount/premiums	—			21			26			—			47
Adjustment for debt extinguishment	—			9			(19		)	—			(10		)
Amortization of intangibles and out-of-market contracts	52			99			—			—			151
Amortization of unearned equity compensation	—			(2		)	41			—			39
Net loss on sale of assets and equity method investments	—			—			14			—			14
Gain on post retirement benefits curtailment	—			(21		)	—			—			(21		)
Impairment losses	4,494			391			31			—			4,916
Changes in derivative instruments	264			(29		)	—			—			235
Changes in deferred income taxes and liability for uncertain tax benefits	(1,092		)	(237		)	2,655			—			1,326
Changes in collateral deposits in support of energy risk management activities	(323		)	(11		)	—			—			(334		)
Proceeds from sale of emission allowances	(24		)	—			—			—			(24		)
Changes in nuclear decommissioning trust liability	(2		)	—			—			—			(2		)
Cash (used)/provided by changes in other working capital	(8,656		)	(907		)	12,183			(2,836		)	(216		)
Cash (used)/provided by continuing operations	(6,887		)	(419		)	8,593			—			1,287
Cash provided by discontinued operations	—			62			—			—			62
Net Cash (Used)/Provided by Operating Activities	(6,887		)	(357		)	8,593			—			1,349
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			70			(70		)	—
Intercompany dividends	—			—			33			(33		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(698		)	—			698			—
Acquisition of business, net of cash acquired	—			(31		)	—			—			(31		)
Capital expenditures	(316		)	(654		)	(59		)	—			(1,029		)
Net cash proceeds from notes receivable	—			18			—			—			18
Proceeds from renewable energy grants	—			82			—			—			82
Proceeds from emission allowances, net of purchases	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	—			16			—			—			16
Cash (used)/provided by continuing operations	(272		)	(1,623		)	31			595			(1,269		)
Cash used by discontinued operations	—			(259		)	—			—			(259		)
Net Cash (Used)/Provided by Investing Activities	(272		)	(1,882		)	31			595			(1,528		)
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 Drop Down Assets, net of cash acquired	—			—			698			(698		)	—
Payment of dividends to common and preferred stockholders	—			—			(201		)	—			(201		)
Net receipts from settlement of acquired derivatives that include financing elements	—			14			—			—			14
Payment for treasury stock	—			—			(437		)	—			(437		)
Distributions from, net of contributions to, noncontrolling interest 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
Payment of debt issuance and hedging costs	—			(21		)	—			—			(21		)
Payments for short and long-term debt	—			(1,116		)	(246		)	—			(1,362		)
Other	—			(22		)	—			—			(22		)
Cash provided/(used) by continuing operations	7,183			1,610			(8,575		)	(595		)	(377		)
Cash used by discontinued operations	—			(55		)	—			—			(55		)
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
Change in cash from discontinued operations	—			(252		)	—			—			(252		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	24			(422		)	49			—			(349		)
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	36			991			644			—			1,671
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	60		$	569		$	693		$	—		$	1,322

(a) All significant intercompany transactions have been eliminated in consolidation.

- Definition

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

+ References + Details

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation

Principles of Consolidation

Segment Reporting

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

Restricted Cash



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Cash and cash equivalents	$	991	$	938	$	853
Funds deposited by counterparties	37		2		55
Restricted cash	508		446		414
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,536	$	1,386	$	1,322

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.

Trade Receivables and Allowance for Doubtful Accounts

Inventory

Property, Plant and Equipment

Asset Impairments

For further discussion of these matters, refer to Note 10, Asset Impairments.

Development Costs and Capitalized Interest

Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for its intended use.

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.

Revenue Recognition

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.

Gross Receipts and Sales Taxes

Cost of Energy for Retail Operations

Derivative Financial Instruments

Foreign Currency Translation and Transaction Gains and Losses

Concentrations of Credit Risk

Fair Value of Financial Instruments

Asset Retirement Obligations

Pensions and Other Postretirement Benefits

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

Investments Accounted for by the Equity Method

Tax Equity Arrangements

Sale-Leaseback Arrangements

Marketing and Advertising Costs

Reorganization Costs

Reorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily reflect personnel costs related to cost savings initiatives.

Business Combinations

Use of Estimates

Reclassifications

Certain prior-year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.

Recent Accounting Developments

Recent Accounting Developments - Guidance Adopted in 2017

Recent Accounting Developments - Guidance Not Yet Adopted

Nuclear Decommissioning Policy

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Reconciliation of Cash and Cash Equivalents, Restricted Cash and Funds Deposited to Cash Flow



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Cash and cash equivalents	$	991	$	938	$	853
Funds deposited by counterparties	37		2		55
Restricted cash	508		446		414
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,536	$	1,386	$	1,322

Changes in Redeemable Noncontrolling Interest

The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2017, 2016, and 2015.



	(In millions)
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	33
Non-cash adjustments to redeemable noncontrolling interest	23
Comprehensive loss attributable to redeemable noncontrolling interest	(38		)
Balance as of December 31, 2016	46
Distributions to redeemable noncontrolling interest	(2		)
Contributions from redeemable noncontrolling interest	99
Non-cash adjustments to redeemable noncontrolling interest	7
Comprehensive loss attributable to redeemable noncontrolling interest	(72		)
Balance as of December 31, 2017	$	78

Discontinued Operations, Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Summary of Results of Discontinued Operations

Summarized results of discontinued operations were as follows:



	Year ended December 31,
(In millions)	2017			2016
Operating revenues	$	646		$	1,862
Operating costs and expenses	(702		)	(1,896		)
Gain on sale of assets	—			294
Other expenses	(98		)	(168		)
(Loss)/Income from operations of discontinued components, before tax	(154		)	92
Income tax expense	9			11
(Loss)/Income from operations of discontinued components	(163		)	81
Interest income - affiliate	8			11
(Loss)/Income from operations of discontinued components, net of tax	(155		)	92
Pre-tax loss on deconsolidation	(208		)	—
Settlement consideration and services credit	(289		)	—
Pension and post-retirement liability assumption	(131		)	—
Other	(6		)	—
Loss on disposal of discontinued components, net of tax	(634		)	—
(Loss)/Income from discontinued operations, net of tax	$	(789	)	$	92



(In millions)	December 31, 2016
Cash and cash equivalents	$	1,034
Other current assets	885
Current assets - discontinued operations	1,919
Property, plant and equipment, net	2,543
Other non-current assets	418
Non-current assets - discontinued operations	2,961
Current portion of long term debt and capital leases	704
Other current liabilities	506
Current liabilities - discontinued operations	1,210
Long-term debt and capital leases	2,050
Out-of-market contracts	811
Other non-current liabilities	323
Non-current liabilities - discontinued operations	$	3,184

- Definition

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=65878427&loc=SL51721533-107759

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721665-107760

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=64827811&loc=d3e1474-107760

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64827811&loc=d3e1361-107760

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721683-107760

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=84176398&loc=SL51724579-110230

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5C
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721675-107760

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721663-107760

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=84176398&loc=d3e2941-110230

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5B
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721673-107760

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721659-107760

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5A
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721671-107760

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5D
-URI http://asc.fasb.org/extlink&oid=64827811&loc=SL51721677-107760

+ Details

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Estimated Carrying Amounts and Fair Values of Financial Instruments Not Carried at Fair 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,
	2017				2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets
Notes receivable ^(a)	$	16	$	15	$	34	$	34
Liabilities
Long-term debt, including current portion ^(b)	$	16,603	$	16,894	$	16,655	$	16,620

(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.



	As of December 31, 2017				As of December 31, 2016
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	8,934	$	7,960	$	9,205	$	7,415

Assets and Liabilities Measured and Recorded at Fair Value Measured on a Recurring Basis



	As of December 31, 2017
	Fair Value
	Total		Level 1		Level 2		Level 3
	(In millions)
Investments in securities (classified within other non-current assets):
Debt securities	$	19	$	—	$	—	$	19
Available-for-sale securities	3		3		—		—
Nuclear trust fund investments:
Cash and cash equivalents	47		45		2		—
U.S. government and federal agency obligations	43		42		1		—
Federal agency mortgage-backed securities	82		—		82		—
Commercial mortgage-backed securities	14		—		14		—
Corporate debt securities	99		—		99		—
Equity securities	334		334		—		—
Foreign government fixed income securities	5		—		5		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	745		191		509		45
Interest rate contracts	53		—		53		—
Measured using net asset value practical expedient:
Equity securities	68
Total assets	$	1,513	$	616	$	765	$	64
Derivative liabilities:
Commodity contracts	$	693	$	257	$	359	$	77
Interest rate contracts	59		—		59		—
Total liabilities	$	752	$	257	$	418	$	77



	As of December 31, 2016
	Fair Value
	Total		Level 1		Level 2		Level 3

Investments in securities (classified within other non-current assets):
Debt securities	$	17	$	—	$	—	$	17
Available-for-sale securities	10		10		—		—
Nuclear trust fund investments:
Cash and cash equivalents	25		25		—		—
U.S. government and federal agency obligations	73		72		1		—
Federal agency mortgage-backed securities	62		—		62		—
Commercial mortgage-backed securities	17		—		17		—
Corporate debt securities	84		—		84		—
Equity securities	292		292		—		—
Foreign government fixed income securities	3		—		3		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,199		560		549		90
Interest rate contracts	49		—		49		—
Measured using net asset value practical expedient:
Equity securities	54
Total assets	$	1,886	$	960	$	765	$	107
Derivative liabilities:
Commodity contracts	$	1,288	$	494	$	636	$	158
Interest rate contracts	88		—		88		—
Total liabilities	$	1,376	$	494	$	724	$	158

Reconciliation of Beginning and Ending Balances for Financial Instruments that are Recognized at Fair Value using Significant Unobservable Inputs

The following tables reconcile, for the years ended December 31, 2017 and 2016, 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, 2017
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt Securities		Derivatives^(a)			Total
	(In millions)
Beginning balance as of January 1, 2017	$	17	$	(68	)	$	(51	)
Total gains/(losses) realized/unrealized:
Included in earnings	2		43			45
Included in nuclear decommissioning obligations	—		—			—
Purchases	—		(23		)	(23		)
Contracts reclassified to held-for-sale	—		4			4
Transfers into Level 3 ^(b)	—		(1		)	(1		)
Transfers out of Level 3 ^(b)	—		13			13
Ending balance as of December 31, 2017	$	19	$	(32	)	$	(13	)
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2017	$	2	$	6		$	8


(a)	Consists of derivatives assets and liabilities, net.


(b)	Transfers into/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 into/out of Level 3 are from/to Level 2.



	For the Year Ended December 31, 2016
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt Securities		Trust Fund Investments^(c)			Derivatives ^(a)			Total
	(In millions)
Beginning balance as of January 1, 2016	$	17	$	54		$	(22	)	$	49
Total gains/(losses) realized/unrealized:
Included in earnings	—		—			2			2
Included in nuclear decommissioning obligations	—		(1		)	—			(1		)
Purchases	—		1			(29		)	(28		)
Transfers into Level 3 ^(b)	—		—			(18		)	(18		)
Transfer out of Level 3 ^(b)	—		(54		)	(1		)	(55		)
Ending balance as of December 31, 2016	$	17	$	—		$	(68	)	$	(51	)
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	$	—	$	—		$	(13	)	$	(13	)


(a)	Consists of derivatives assets and liabilities, net.


(b)	Transfers into/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 into/out of Level 3 are from/to Level 2.


(c)	All Trust Fund Investments were considered transferred out of Level 3 as these investments are measured using net asset value as a practical expedient and are thus classified outside of the fair value hierarchy as of December 31, 2016.

Schedule of Significant Unobservable Inputs used in Developing Fair Value of Level 3 Positions

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, 2017 and 2016:



	Significant Unobservable Inputs
	December 31, 2017
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	34	$	65	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	142	$	33
FTRs	11		12		Discounted Cash Flow	Auction Prices (per MWh)	(28		)	46		—
	$	45	$	77



	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	$	39	$	108	Discounted Cash Flow	Forward Market Price (per MWh)	$	11		$	104	$	31
FTRs	51		50		Discounted Cash Flow	Auction Prices (per MWh)	(22		)	17		—
	$	90	$	158

Fair Value Inputs, Sensitivity Analysis

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2017 and 2016:



Significant Unobservable Input	Position	Change In Input	Impact on Fair Value Measurement
Forward Market Price Power	Buy	Increase/(Decrease)	Higher/(Lower)
Forward Market Price Power	Sell	Increase/(Decrease)	Lower/(Higher)
FTR Prices	Buy	Increase/(Decrease)	Higher/(Lower)
FTR Prices	Sell	Increase/(Decrease)	Lower/(Higher)

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)
Financial institutions	14	%
Utilities, energy merchants, marketers and other	86
Total	100	%



Category	Net Exposure^{(a) (b)} (% of Total)
Investment grade	69	%
Non-Investment grade/Non-Rated	31
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.

Accounting for Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Net Notional Volume Buy/(sell) of NRG's Open Derivative Transactions Broken Out By Commodity



		Total Volume
Commodity	Units	December 31, 2017			December 31, 2016
		(In millions)
Emissions	Short Ton	1			—
Coal	Short Ton	21			35
Natural Gas	MMBtu	(17		)	(53		)
Oil	Barrel	—			1
Power	MWh	14			7
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	3,876		$	3,429
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, 2017		December 31, 2016		December 31, 2017		December 31, 2016
Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	1	$	—	$	5	$	28
Interest rate contracts long-term	11		12		11		41
Total Derivatives Designated as Cash Flow or Fair Value Hedges	12		12		16		69
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	9		—		15		7
Interest rate contracts long-term	32		37		28		12
Commodity contracts current	616		1,067		535		1,057
Commodity contracts long-term	129		132		158		231
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	786		1,236		736		1,307
Total Derivatives	$	798	$	1,248	$	752	$	1,376

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, 2017	(In millions)
Commodity contracts:
Derivative assets	$	745		$	(578	)	$	(11	)	$	156
Derivative liabilities	(693		)	578			73			(42		)
Total commodity contracts	52			—			62			114
Interest rate contracts:
Derivative assets	53			(3		)	—			50
Derivative liabilities	(59		)	3			—			(56		)
Total interest rate contracts	(6		)	—			—			(6		)
Total derivative instruments	$	46		$	—		$	62		$	108



	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	$	1,199		$	(1,021	)	$	(13	)	$	165
Derivative liabilities	(1,288		)	1,021			13			(254		)
Total commodity contracts	(89		)	—			—			(89		)
Interest rate contracts:
Derivative assets	49			(4		)				45
Derivative liabilities	(88		)	4			—			(84		)
Total interest rate contracts	(39		)	—			—			(39		)
Total derivative instruments	$	(128	)	$	—		$	—		$	(128	)

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, 2017
	Interest Rate			Total
	(In millions)
Accumulated OCI balance at December 31, 2016	$	(66	)	$	(66	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	12			12
Mark-to-market of cash flow hedge accounting contracts	—			—
Accumulated OCI balance at December 31, 2017, net of $8 tax	$	(54	)	$	(54	)
Losses expected to be realized from other comprehensive loss during the next 12 months, net of $2 tax	$	(12	)	$	(12	)



	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	)



	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	)

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



	Year Ended December 31,
	2017			2016			2015
	(In millions)
Unrealized mark-to-market results
Reversal of previously recognized unrealized loss/(gains) on settled positions related to economic hedges	$	47		$	(128	)	$	(162	)
Reversal of acquired gain positions related to economic hedges	—			(12		)	(22		)
Net unrealized gains/(losses) on open positions related to economic hedges	146			6			(9		)
Total unrealized mark-to-market gains/(losses) for economic hedging activities	193			(134		)	(193		)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(25		)	10			(46		)
Reversal of acquired gain positions related to trading activity	—			—			(14		)
Net unrealized gains/(losses) on open positions related to trading activity	14			18			(16		)
Total unrealized mark-to-market (losses)/gains for trading activity	(11		)	28			(76		)
Total unrealized gains/(losses)	$	182		$	(106	)	$	(269	)



	Year Ended December 31,
	2017			2016			2015
	(In millions)
Unrealized gains/(losses) included in operating revenues	$	228		$	(614	)	$	(210	)
Unrealized (losses)/gains included in cost of operations	(46		)	508			(59		)
Total impact to statement of operations — energy commodities	$	182		$	(106	)	$	(269	)
Total impact to statement of operations — interest rate contracts	$	9		$	36		$	17

Nuclear Decommissioning Trust Fund (Tables)

12 Months Ended

Dec. 31, 2017

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



	As of December 31, 2017							As of December 31, 2016
(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	$	47	$	—	$	—	—	$	25	$	—	$	—	—
U.S. government and federal agency obligations	43		1		—		11	73		1		—		11
Federal agency mortgage-backed securities	82		1		1		23	62		1		1		25
Commercial mortgage-backed securities	13		—		—		20	17		—		1		26
Corporate debt securities	99		2		1		11	84		1		2		11
Equity securities	403		272		—		—	346		214		—		—
Foreign government fixed income securities	5		—		—		9	3		—		—		9
Total	$	692	$	276	$	2		$	610	$	217	$	4

Summary of Proceeds From Sales of Available-For-Sale securities and the related realized gains and losses



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Realized gains	$	22	$	26	$	21
Realized losses	8		11		14
Proceeds from sale of securities	501		510		631

Inventory (Tables)

12 Months Ended

Dec. 31, 2017

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of:



	As of December 31,
	2017		2016
	(In millions)
Fuel oil	$	90	$	142
Coal/Lignite	126		219
Natural gas	24		28
Spare parts	292		332
Total Inventory	$	532	$	721

Notes Receivable (Tables)

12 Months Ended

Dec. 31, 2017

Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]

Schedule of Notes Receivable

The Company's notes receivable were as follows:



	As of December 31,
	2017		2016
	(In millions)
Notes receivable	$	16	$	34
Less current maturities^(a)	14		18
Total notes receivable — non-current	$	2	$	16


(a)	The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

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
	2017			2016			Lives
	(In millions)
Facilities and equipment	$	15,907		$	18,698		1-40 Years
Land and improvements	710			750
Nuclear fuel	236			226			5 Years
Office furnishings and equipment	434			412			2-10 Years
Construction in progress	1,086			619
Total property, plant, and equipment	18,373			20,705
Accumulated depreciation	(4,465		)	(5,336		)
Net property, plant, and equipment	$	13,908		$	15,369

Goodwill and Other Intangibles (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Summary of the Components of Intangible Assets Subject to Amortization

The following tables summarize the components of NRG's intangible assets subject to amortization:



				Contracts
Year Ended December 31, 2017	Emission Allowances			Energy Supply			Fuel			Customer			Customer Relationships			Marketing Partnerships			Trade Names			PPA			Other			Total
	(In millions)
January 1, 2017	$	789		$	54		$	72		$	16		$	816		$	88		$	342		$	1,286		$	198		$	3,661
Purchases	31			—			—			—			—			—			—			—			32			63
Acquisition of businesses	—			—			—			—			18			—			—			—			—			18
Usage	(10		)	—			—			—			—			—			—			—			(28		)	(38		)
Write-off of fully amortized balances^(a)	—			(54		)	(23		)	—			—			—			—			—			—			(77		)
Impairment	(20		)	—			—			—			—			—			—			(6		)	—			(26		)
Other	(23		)	—			—			—			—			—			—			5			(19		)	(37		)
December 31, 2017	767			—			49			16			834			88			342			1,285			183			3,564
Less accumulated amortization	(591		)	—			(45		)	(9		)	(698		)	(54		)	(182		)	(205		)	(34		)	(1,818		)
Net carrying amount	$	176		$	—		$	4		$	7		$	136		$	34		$	160		$	1,080		$	149		$	1,746

(a) Adjusted for write-off of fully amortized energy supply contracts of $54 million and fuel contracts of $23 million.



				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	$	816		$	54		$	72		$	16		$	834		$	88		$	342		$	1,286		$	213		$	3,721
Purchases	13			—			—			—			—			—			—			—			34			47
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	(6		)	—			—			—			—			—			—			—			—			(6		)
December 31, 2016	789			54			72			16			816			88			342			1,286			198			3,661
Less accumulated amortization	(518		)	(54		)	(67		)	(8		)	(663		)	(49		)	(159		)	(143		)	(27		)	(1,688		)
Net carrying amount	$	271		$	—		$	5		$	8		$	153		$	39		$	183		$	1,143		$	171		$	1,973

(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.

Schedule of Amortization of Intangible Expense

The following table presents NRG's amortization of intangible assets for each of the past three years:



	Years Ended December 31,
Amortization	2017		2016		2015
	(In millions)
Emission allowances	$	73	$	66	$	60
Energy supply contracts	—		7		5
Fuel contracts	1		2		2
Customer contracts	1		2		2
Customer relationships	35		49		67
Marketing partnerships	5		8		14
Trade names	23		22		23
Power purchase agreements	62		64		51
Other	7		11		14
Total amortization	$	207	$	231	$	238

Schedule of Estimated Amortization of Intangible Assets for 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)
2018	$	33	$	1	$	1	$	25	$	5	$	22	$	64	$	8	$	159
2019	30		—		1		21		4		22		64		8		150
2020	16		—		1		17		4		22		64		8		132
2021	16		—		1		13		4		22		64		8		128
2022	15		—		1		7		3		22		64		8		120

Schedule of Out of Market Contracts, Future Amortization

The following table summarizes the estimated amortization related to NRG's out-of-market contracts:



Year Ended December 31,	Power Contracts		Leases		Total
	(In millions
2018	$	16	$	9	$	25
2019	16		9		25
2020	17		9		26
2021	14		9		23
2022	1		9		10

Debt and Capital Leases (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Long-term Debt and Capital Leases

Long-term debt and capital leases consisted of the following:



(In millions, except rates)	December 31,						December 31, 2017
	2017			2016			Interest Rate % ^(a)
Recourse debt:
Senior notes, due 2018	$	—		$	398		7.625
Senior notes, due 2021	—			207			7.875
Senior notes, due 2022	992			992			6.250
Senior notes, due 2023	—			869			6.625
Senior notes, due 2024	733			733			6.250
Senior notes, due 2026	1,000			1,000			7.250
Senior notes, due 2027	1,250			1,250			6.625
Senior notes, due 2028	870			—			5.750
Term loan facility, due 2023	1,872			1,891			L+2.25
Tax-exempt bonds	465			455			4.125 - 6.00
Subtotal recourse debt	7,182			7,795
Non-recourse debt:
NRG Yield Operating LLC Senior Notes, due 2024	500			500			5.375
NRG Yield Operating LLC Senior Notes, due 2026	350			350			5.000
NRG Yield, Inc. Convertible Senior Notes, due 2019	345			345			3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020	288			288			3.250
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 ^(b)	55			—			L+2.500
El Segundo Energy Center, due 2023	400			443			L+1.75 - L+2.375
Marsh Landing, due 2023	318			370			L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035	926			965			5.696 - 7.015
Walnut Creek, term loans due 2023	267			310			L+1.625
Utah Portfolio, due 2022	278			287			L+2.625
Tapestry, due 2021	162			172			L+1.625
CVSR, due 2037	746			771			2.339 - 3.775
CVSR HoldCo, due 2037	194			199			4.680
Alpine, due 2022	135			145			L+1.750
Energy Center Minneapolis, due 2025	83			96			3.55 - 5.95
Energy Center Minneapolis, due 2031	125			125			3.55
Viento, due 2023	163			178			L+3.00
NRG Yield - other	579			603			various
Subtotal NRG Yield debt (non-recourse to NRG) ^(c)	5,914			6,147
Ivanpah, due 2033 and 2038	1,073			1,113			2.285 - 4.256
Carlsbad Energy Project ^(c)	427			—			L+1.625 -.04120
Agua Caliente, due 2037	818			849			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	89			—			5.430
Cedro Hill, due 2029 ^(c)	151			163			L+1.75
Midwest Generation, due 2019	152			231			4.390
NRG Other Renewables^(c)	647			269
NRG Other	180			137			various
Subtotal other non-recourse debt	3,537			2,762
Subtotal all non-recourse debt	9,451			8,909
Subtotal long-term debt (including current maturities)	16,633			16,704
Capital leases	5			6			various
Subtotal long-term debt and capital leases (including current maturities)	16,638			16,710
Less current maturities	(688		)	(516		)
Less debt issuance costs	(204		)	(188		)
Discounts	(30		)	(49		)
Total long-term debt and capital leases	$	15,716		$	15,957


(a)	As of December 31, 2017, L+ equals 3 month LIBOR plus x%, except for the Utah Solar Portfolio where L+ equals 1 month LIBOR plus 2.629%.


(b)	Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement


(c)	Debt associated with the asset sales announced in February 2018

Long-term debt includes the following discounts:



	As of December 31,
	2017			2016
	(In millions)
Term loan facility, due 2023 ^(a)	$	(7	)	$	(9	)
Yield, Inc. Convertible notes, due 2019	(5		)	(10		)
Yield, Inc. Convertible notes, due 2020	(13		)	(17		)
Midwest Generation, due 2019	(5		)	(13		)
Total discounts	$	(30	)	$	(49	)


(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.

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, 2017 are as follows:



	(In millions)
2018	$	695
2019	933
2020	805
2021	606
2022	1,854
Thereafter	11,745
Total	$	16,638

Schedule of Tax Exempt Bonds

Tax Exempt Bonds



	As of December 31,
	2017		2016		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	32		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	$	465	$	455

Schedule of Project Level Debt Assumed During Acquisition



Amount in millions, except rates	Lease Financing Arrangement				Letter of Credit Facility
Non-Recourse Debt	Amount Outstanding as of December 31, 2017		Interest Rate	Maturity Date	Amount Outstanding as of December 31, 2017		Interest Rate	Maturity Date
Alta Wind I	$	231	7.015%	12/30/2034	$	16	3.00% - 3.25%	1/5/2021
Alta Wind II	183		5.696%	12/30/2034	27		1.250%	3/21/2022
Alta Wind III	191		6.067%	12/30/2034	27		1.750%	various
Alta Wind IV	123		5.938%	12/30/2034	19		1.750%	various
Alta Wind V	198		6.071%	6/30/2035	30		1.750%	various
Total	$	926			$	119

Debt Instrument Redemption

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	%



	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.



	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
Amount in millions, except rates
7.625% senior notes due 2018	$	398	$	411	101.42	%
7.875% senior notes due 2021	206		218		102.63	%
6.625% senior notes due 2023	869		915		103.57	%
Total	$	1,473	$	1,544

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	%

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	%

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	%

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, 2017.



	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2017 (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	%	various		3-mo. LIBOR	340		various	various
South Trent Wind LLC	75	%	3.265	%	3-mo. LIBOR	40		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	26		September 30, 2011	December 31, 2029
NRG Solar Alpine LLC	85	%	various		3-mo. LIBOR	115		various	various
NRG Solar Avra Valley LLC	85	%	2.333	%	3-mo. LIBOR	46		November 30, 2012	November 30, 2030
NRG Marsh Landing	75	%	3.244	%	3-mo. LIBOR	295		June 28, 2013	June 30, 2023
Utah Portfolio	80	%	various		1-mo. LIBOR	223		various	September 30, 2036
DGPV 4	85	%	various		3-mo. LIBOR	95		various	various
Other	75	%	various		various	653		various	various
EME Project Financings						—
Broken Bow	75	%	various		3-mo. LIBOR	55		various	various
Cedro Hill	90	%	various		3-mo. LIBOR	136		various	various
Crofton Bluffs	75	%	various		3-mo. LIBOR	36		various	various
Laredo Ridge	75	%	2.310	%	3-mo. LIBOR	75		March 31, 2011	March 31, 2026
Tapestry	75	%	2.210	%	3-mo. LIBOR	146		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	148		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	239		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-mo. LIBOR	45		June 28, 2013	May 21, 2023
Alta Wind Project Financings
AWAM	100	%	2.470	%	3-mo. LIBOR	17		May 22, 2013	May 15, 2031
Total						$	3,876

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 835
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21521-112644

+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of company's ARO obligations and related additions, reductions and accretion



	(In millions)
Balance as of December 31, 2016	$	735
Revisions in estimates for current obligations	(3		)
Additions	9
Spending for current obligations	(21		)
Accretion — Expense	35
Accretion — Nuclear decommissioning	16
Balance as of December 31, 2017	$	771

Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Schedule of Net Benefit Cost (Credit) Related to Pension and Other Postretirement Benefit Plans Components [Table Text Block]

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
	2017			2016			2015
	(In millions)
Service cost benefits earned	$	26		$	30		$	32
Interest cost on benefit obligation	43			43			53
Expected return on plan assets	(58		)	(60		)	(62		)
Amortization of unrecognized net loss	4			2			2
Net periodic benefit cost	$	15		$	15		$	25



	Year Ended December 31,
	Other Postretirement Benefits
	2017			2016			2015
	(In millions)
Service cost benefits earned	$	1		$	2		$	3
Interest cost on benefit obligation	4			6			9
Amortization of unrecognized prior service credit	(9		)	(5		)	(5		)
Amortization of unrecognized net (gain)/loss	(1		)	—			1
Curtailment gain	—			—			(14		)
Net periodic benefit (credit)/cost	$	(5	)	$	3		$	(6	)

Schedule of Comparison of Pension Benefit obligation, Other Postretirement Benefit Obligations and Related Plan Assets 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
	2017			2016			2017			2016
	(In millions)
Benefit obligation at January 1	$	1,241		$	1,196		$	128		$	178
Service cost	26			30			1			2
Interest cost	43			43			4			6
Plan amendments	—			—			(1		)	(42		)
Actuarial loss/(gain)	77			40			6			(2		)
Employee and retiree contributions	—			—			3			3
Benefit payments	(58		)	(68		)	(13		)	(17		)
Benefit obligation at December 31	1,329			1,241			128			128
Fair value of plan assets at January 1	953			916			—			—
Actual return on plan assets	173			72			—			—
Employee and retiree contributions	—			—			3			3
Employer contributions	36			33			10			14
Benefit payments	(58		)	(68		)	(13		)	(17		)
Fair value of plan assets at December 31	1,104			953			—			—
Funded status at December 31 — excess of obligation over assets	$	(225	)	$	(288	)	$	(128	)	$	(128	)
Less: GenOn postretirement obligation^(a)	—			—			38			46
Add: Retained obligation in bankruptcy proceeding^(a)	—			—			(25		)	(25		)
Net obligation for NRG	$	(225	)	$	(288	)	$	(115	)	$	(107	)


(a)	The difference between GenOn's postretirement benefit obligation and NRG's retained obligation of $13 million and $21 million is presented in noncurrent liabilities for discontinued operations as of December 31, 2017 and 2016, respectively.

Schedule of Amounts Recognized in Balance Sheet

Amounts recognized in NRG's balance sheets were as follows:



	As of December 31,
	Pension Benefits				Other Postretirement Benefits
	2017		2016		2017			2016
	(In millions)
Current liabilities	$	—	$	—	$	7		$	8
Less: GenOn other postretirement benefits^(a)	—		—		(3		)	(5		)
Total current liabilities	$	—	$	—	$	4		$	3

Non-current liabilities	$	225	$	288	$	121		$	120
Less: GenOn other postretirement benefits^(a)	—		—		(10		)	(16		)
Total non-current liabilities	$	225	$	288	$	111		$	104


(a)	The difference between GenOn's postretirement benefit obligation and NRG's retained obligation of $13 million and $21 million is presented in noncurrent liabilities for discontinued operations as of December 31, 2017 and 2016, respectively.

Schedule of Amounts Recognized in OCI Not Yet Recognized as Components of Net Periodic Benefit Costs

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
	2017			2016			2017			2016
	(In millions)
Net loss/(gain)	$	53		$	94		$	(4	)	$	(11	)
Prior service cost/(credit)	3			3			(37		)	(45		)
Total accumulated OCI	$	56		$	97		$	(41	)	$	(56	)
Less: GenOn (deconsolidated June 14, 2017)	(22		)	(37		)	10			8
Net accumulated OCI	$	34		$	60		$	(31	)	$	(48	)

Schedule of Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income

Other changes in plan assets and benefit obligations recognized in OCI were as follows:



	Year Ended December 31,
	Pension Benefits						Other Postretirement Benefits
	2017			2016			2017			2016
	(In millions)
Net actuarial (gain)/loss	$	(37	)	$	28		$	6		$	(2	)
Amortization of net actuarial (gain)/loss	(4		)	(2		)	1			—
Prior service credit	—			—			(1		)	(41		)
Amortization of prior service cost	—			—			9			5
Total recognized in OCI	$	(41	)	$	26		$	15		$	(38	)
Less: GenOn (deconsolidated June 14, 2017)	15			$	(17	)	$	2		$	3
Net recognized in OCI	$	(26	)	$	9		$	17		$	(35	)
Less: GenOn (deconsolidated June 14, 2017)	15			(17		)	3			3
Net recognized in net periodic pension (credit)/cost and OCI	$	(11	)	$	24		$	13		$	39

Schedule of Benefit Obligations Significant Components

The following table presents the balances of significant components of NRG's pension plan:



	As of December 31,
	Pension Benefits
	2017		2016
	(In millions)
Projected benefit obligation	$	1,329	$	1,241
Accumulated benefit obligation	1,255		1,174
Fair value of plan assets	1,104		953

Schedule of Fair Value of Pension Plan Assets by Asset Category and Level within the Fair Value Hierarchy



	Fair Value Measurements as of December 31, 2017
	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	$	—	$	256	$	256
Common/collective trust investment — non-U.S. equity	—		66		66
Common/collective trust investment — non-core assets	—		178		178
Common/collective trust investment — fixed income	—		230		230
Short-term investment fund	5		—		5
Subtotal fair value	$	5	$	730	$	735
Measured at net asset value practical expedient
Common/collective trust investment — non-U.S. equity					94
Common/collective trust investment — fixed income					233
Partnerships/joint ventures					42
Total fair value					$	1,104



	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	—		71		71
Common/collective trust investment — global equity	—		104		104
Common/collective trust investment — fixed income	—		190		190
Short-term investment fund	3		—		3
Subtotal fair value	$	3	$	648	$	651
Measured at net asset value practical expedient
Common/collective trust investment — non-U.S. equity					78
Common/collective trust investment — fixed income					193
Partnerships/joint ventures					31
Total fair value					$	953

Schedule of Assumptions Used to Calculate 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	2017		2016		2017		2016
Discount rate	3.71	%	4.26	%	3.71	%	4.29	%
Rate of compensation increase	3.00	%	3.00	%	N/A		N/A
Health care trend rate	—		—		8.2% grading to 4.5% in 2025		7.0% 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	2017		2016		2015		2017		2016		2015
Discount rate	4.26	%	4.52	%	4.16	%	4.29	%	4.55	%	4.20	%
Expected return on plan assets	6.85	%	6.65	%	6.36	%	—		—		—
Rate of compensation increase	3.00	%	3.00	%	3.45	%	—		—		—
Health care trend rate	—		—		—		7.0% grading to 5.0% in 2025		7.25% grading to 5.0% in 2025		8.6% grading to 5.0% in 2023

Schedule of Target Allocation of Pension Plan Assets

The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2017:



U.S. equity	22	%
Non-U.S. equity	14	%
Non-core assets	19	%
U.S. fixed income	45	%

Schedule of Performance Benchmarks [Table Text Block]

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
Non-core assets^(a)		Various (per underlying asset class)
Fixed income securities		Barclays Capital Long Term Government/Credit Index & Barclays Strips 20+ Index

(a)

Schedule of Expected Benefit Payments

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)
2018	$	68	$	7	$	—
2019	71		8		—
2020	75		8		—
2021	79		8		—
2022	82		8		—
2023-2027	421		33		1

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates



	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		)

Schedule of Benefit Costs and Other Changes Recognized in the Financial Statements 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
	2017			2016			2017			2016
	(In millions)
Funded status — STPNOC benefit plans	$	(76	)	$	(74	)	$	(24	)	$	(23	)
Net periodic benefit cost/(credit)	8			7			(3		)	(2		)
Other changes in plan assets and benefit obligations recognized in other comprehensive (loss)/income	(6		)	11			5			(1		)

Defined Contribution Plan Contributions

The Company's contributions to these plans were as follows:



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Company contributions to defined contribution plans	$	56	$	55	$	53

Capital Structure (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Changes in NRG's common shares issued and outstanding

The following table reflects the changes in NRG's common shares issued and outstanding for each period presented:



	Common
	Issued	Treasury		Outstanding
Balance as of December 31, 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
Shares issued under ESPP	—	560,769		560,769
Shares issued under LTIPs	739,309	—		739,309
Balance as of December 31, 2017	418,323,134	(101,580,045	)	316,743,089

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



Equity Instrument	Common Stock Reserve Balance
Long-term incentive plans	19,597,433

Dividends paid per common share

The following table lists the dividends paid per common share during 2017, 2016 and 2015:



	Fourth Quarter		Third Quarter		Second Quarter		First Quarter
2017	$	0.030	$	0.030	$	0.030	$	0.030
2016	$	0.030	$	0.030	$	0.030	$	0.145
2015	$	0.145	$	0.145	$	0.145	$	0.145

Class of 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.

Temporary Equity

The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended December 31, 2017, 2016, and 2015:



	(In millions)
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	—
Balance as of December 31, 2017	$	—

Investments Accounted for by the Equity Method and Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Summary NRG's equity method investments

The following table summarizes NRG's equity method investments as of December 31, 2017:



Name	Economic Interest		Investment Balance
			(In millions)
Avenal Solar Holdings LLC ^(a)	50.0	%	$	(6	)
Desert Sunlight Investment Holdings, LLC ^(a)	25.0	%	272
Elkhorn Ridge Wind, LLC ^(a)	47.0	%	73
GenConn Energy LLC ^(a)	50.0	%	102
Four Brothers Solar, LLC^(a)(c)	50.0	%	213
Granite Mountain Holdings, LLC ^(a)(c)	50.0	%	78
Iron Springs Holdings, LLC^(a)(c)	50.0	%	54
Midway-Sunset Cogeneration Company	50.0	%	16
San Juan Mesa Wind Project, LLC ^(a)	75.0	%	66
Watson Cogeneration Company	49.0	%	21
Gladstone Power Station ^(b)	37.5	%	139
Other^(d)	Various		10
Total equity investments in affiliates			$	1,038

(a) Equity method investments owned by NRG Yield

(b) Gladstone Power Station is located in Australia

(d) Refer to Note 10 - Asset Impairments for discussion of NRG's investment in Petra Nova Parish Holdings, LLC.

Undistributed earnings by equity investment



	As of December 31,
	2017		2016
	(In millions)
Undistributed earnings from equity investments	$	120	$	101

Summary of Financial Information for Consolidated VIEs

The summarized financial information for the Company's consolidated VIEs consisted of the following:



(In millions)	December 31, 2017		December 31, 2016
Current assets	$	118	$	87
Net property, plant and equipment	2,337		1,534
Other long-term assets	658		954
Total assets	3,113		2,575
Current liabilities	96		59
Long-term debt	661		442
Other long-term liabilities	209		183
Total liabilities	966		684
Redeemable noncontrolling interests	78		46
Noncontrolling interests	507		529
Net assets less noncontrolling interests	$	1,562	$	1,316

Earnings /Loss Per Share (Tables)

12 Months Ended

Dec. 31, 2017

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,
	2017			2016			2015
	(In millions, except per share amounts)
Basic and diluted loss per share attributable to NRG common stockholders
Net loss attributable to NRG Energy, Inc.	$	(2,153	)	$	(774	)	$	(6,382	)
Dividends for preferred shares	—			5			20
Gain on redemption of 2.822% redeemable perpetual preferred shares	—			(78		)	—
Loss Available to Common Stockholders	$	(2,153	)	$	(701	)	$	(6,402	)
Weighted average number of common shares outstanding	317			316			329
Loss per weighted average common share — basic and diluted	$	(6.79	)	$	(2.22	)	$	(19.46	)

Summary of NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings per share

The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted loss per share:



	Year Ended December 31,
	2017	2016	2015
	(In millions of shares)
Equity compensation	5	5	6
Embedded derivative of 2.822% redeemable perpetual preferred stock	—	—	16
Total	5	5	22

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Reporting Information



	For the Year Ended December 31, 2017
	Generation^(a)			Retail ^(a)			Renewables^(a)			NRG Yield^(a)			Corporate^(a)			Eliminations				Total
	(In millions)
Operating revenues^(a)	$	3,773		$	6,380		$	424		$	1,009		$	14		$	(971	)		$	10,629
Operating expenses	3,300			5,372			211			348			220			(964		)		8,487
Depreciation and amortization	377			117			196			334			32			—				1,056
Impairment losses	1,504			7			154			44			—			—				1,709
Development costs	13			2			45			—			7			—				67
Total operating cost and expenses	5,194			5,498			606			726			259			(964		)		11,319
Other income - affiliate	—			—			—			—			87			—				87
Gain/(loss) on sale of assets	20			—			(5		)	—			1			—				16
Operating (loss)/income	(1,401		)	882			(187		)	283			(157		)	(7		)		(587		)
Equity in (losses)/earnings of unconsolidated affiliates	(14		)	—			—			71			6			(32		)		31
Impairment losses on investments	(74		)	—			—			—			(5		)	—				(79		)
Other income, net	22			1			—			4			11			—				38
Loss on debt extinguishment	—			—			(1		)	(3		)	(49		)	—				(53		)
Interest expense	(29		)	(6		)	(98		)	(306		)	(451		)	—				(890		)
(Loss)/income from continuing operations before income taxes	(1,496		)	877			(286		)	49			(645		)	(39		)		(1,540		)
Income tax expense/(benefit)	2			(9		)	(20		)	72			(37		)	—				8
Net (loss)/income from continuing operations	$	(1,498	)	$	886		$	(266	)	$	(23	)	$	(608	)	$	(39	)		$	(1,548	)
Loss from discontinued operations, net of income tax	—			—			—			—			(789		)	—				$	(789	)
Net (Loss)/Income	(1,498		)	886			(266		)	(23		)	(1,397		)	(39		)		(2,337		)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests	—			2			(103		)	(87		)	(4		)	8				(184		)
Net (loss)/income attributable to NRG Energy, Inc.	$	(1,498	)	$	884		$	(163	)	$	64		$	(1,393	)	$	(47	)		$	(2,153	)

Balance sheet
Equity investments in affiliates	$	179		$	—		$	4		$	852		$	3		$	—			$	1,038
Capital expenditures ^(b)	481			82			521			31			12			—				1,127
Goodwill	165			374			—			—			—			—				539
Total assets	$	7,209		$	2,630		$	5,129		$	8,283		$	8,919		$	(8,852	)	—	$	23,318



(a) Inter-segment sales and net derivative gains and losses included in operating revenues	$	910	$	5	$	31	$	—	$	25	$	—	$	971

(b) Includes accruals.



	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)	$	3,833		$	6,335		$	406		$	1,035		$	77		$	(1,174	)	$	10,512
Operating expenses	3,545			5,164			217			325			323			(1,178		)	8,396
Depreciation and amortization	516			111			185			303			57			—			1,172
Impairment losses	430			1			54			185			32			—			702
Development costs	15			4			40			—			30			—			89
Total operating cost and expenses	4,506			5,280			496			813			442			(1,178		)	10,359
Other income - affiliate	—			—			—			—			193			—			193
Loss on sale of assets	—			(1		)	—			—			(79		)				(80		)
Operating (loss)/income	(673		)	1,054			(90		)	222			(251		)	4			266
Equity in (losses)/earnings of unconsolidated affiliates	(5		)	—			(58		)	60			13			17			27
Impairment losses on investments	(142		)	—			(105		)	—			(21		)	—			(268		)
Other income, net	21			(6		)	1			3			19			(4		)	34
Loss on debt extinguishment	—			—			—			—			(142		)	—			(142		)
Interest expense	(26		)	6			(98		)	(284		)	(495		)	2			(895		)
(Loss)/income from continuing operations before income taxes	(825		)	1,054			(350		)	1			(877		)	19			(978		)
Income tax (benefit)/expense	(1		)	1			(20		)	(1		)	26			—			5
Net (loss)/income from continuing operations	(824		)	1,053			(330		)	2			(903		)	19			(983		)
Income from discontinued operations, net of income tax	—			—			—			—			92						92
Net (Loss)/Income	(824		)	1,053			(330		)	2			(811		)	19			(891		)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	—			(2		)	(13		)	(54		)	18			(66		)	(117		)
Net (loss)/income attributable to NRG Energy, Inc.	$	(824	)	$	1,055		$	(317	)	$	56		$	(829	)	$	85		$	(774	)

Balance sheet
Equity investments in affiliates	$	204		$	—		$	26		$	886		$	4		$	—		$	1,120
Capital expenditures^(b)	522			12			330			23			110			—			997
Goodwill	276			374			12			—			—			—			662
Total assets	$	13,514		$	2,332		$	4,921		$	8,962		$	11,891		$	(10,938	)	$	30,682



(a) Inter-segment sales and net derivative gains and losses included in operating revenues	$	1,033	$	4	$	24	$	8	$	105	$	—	$	1,174

(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)	$	5,179		$	6,913		$	383		$	968		$	38		$	(1,153	)	$	12,328
Operating expenses	4,198			6,138			187			338			502			(1,135		)	10,228
Depreciation and amortization	693			132			176			303			47			—			1,351
Impairment losses	4,655			36			13			1			133			22			4,860
Development costs	26			4			61			—			63			—			154
Total operating costs and expenses	9,572			6,310			437			642			745			(1,113		)	16,593
Other income - affiliate	—			—			—			—			193			—			193
Gain on postretirement benefits curtailment	21			—			—			—			—			—			21
Operating (loss)/income	(4,372		)	603			(54		)	326			(514		)	(40		)	(4,051		)
Equity in earnings/(losses)of unconsolidated affiliates	10			—			(7		)	31			—			2			36
Impairment losses on investments	(14		)	—			—			—			(42		)	—			(56		)
Other income, net	18			(4		)	3			3			13			(7		)	26
Loss on sale of equity method investment	—			—			—			—			(14		)	—			(14		)
Loss on debt extinguishment	—			—			—			(9		)	19			—			10
Interest expense	(25		)	2			(79		)	(267		)	(574		)	6			(937		)
(Loss)/income from continuing operations before income taxes	(4,383		)	601			(137		)	84			(1,112		)	(39		)	(4,986		)
Income tax expense/(benefit)	—			1			(18		)	12			1,350			—			1,345
Net (loss)/income from continuing operations	$	(4,383	)	600			(119		)	72			(2,462		)	(39		)	(6,331		)
Loss from discontinued operations, net of income tax	—			—			—			—			(105		)	—			(105		)
Net (Loss)/Income	(4,383		)	600			(119		)	72			(2,567		)	(39		)	(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.	$	(4,383	)	$	600		$	(125	)	$	53		$	(2,530	)	$	3		$	(6,382	)



(a) Inter-segment sales and net derivative gains and losses included in operating revenues	$	896	$	6	$	31	$	29	$	191	$	—	$	1,153

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

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,
	2017			2016			2015
	(In millions, except percentages)
Current
State	$	19		$	6		$	9
Total — current	19			6			9
Deferred
U.S. Federal	(6		)	3			1,020
State	(7		)	(6		)	315
Foreign	2			2			1
Total — deferred	(11		)	(1		)	1,336
Total income tax expense	$	8		$	5		$	1,345
Effective tax rate	(0.5		)%	(0.5		)%	(27.0		)%

Domestic and foreign components of income/(loss) before income tax (benefit)/expense

The following represents the domestic and foreign components of loss before income tax expense:



	Year Ended December 31,
	2017			2016			2015
	(In millions)
U.S.	$	(1,557	)	$	(989	)	$	(4,997	)
Foreign	17			11			11
Total	$	(1,540	)	$	(978	)	$	(4,986	)

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,
	2017			2016			2015
	(In millions, except percentages)
Loss before income taxes	$	(1,540	)	$	(978	)	$	(4,986	)
Tax at 35%	(539		)	(342		)	(1,745		)
State taxes	19			—			(215		)
Foreign operations	2			10			1
Federal and state tax credits, excluding PTCs	—			—			(5		)
Tax Act - corporate income tax rate change	733			—			—
Valuation allowance due to corporate income tax rate change	(660		)	—			—
Valuation allowance - current period activities	482			398			3,023
Impact of non-taxable equity earnings	(5		)	22			(10		)
Book goodwill impairment	30			—			340
Net interest accrued on uncertain tax positions	—			1			(3		)
Production tax credits	(20		)	(26		)	(33		)
Recognition of uncertain tax benefits	(5		)	2			(15		)
Tax expense attributable to consolidated partnerships	4			(1		)	12
State rate change including true-up to current period activity	18			(59		)	(7		)
AMT refundable credit	(64		)	—			—
Other	13			—			2
Income tax expense	$	8		$	5		$	1,345
Effective income tax rate	(0.5		)%	(0.5		)%	(27.0		)%

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,
	2017			2016
	(In millions)
Deferred tax liabilities:
Emissions allowances	$	15		$	31
Derivatives, net	15			—
Cumulative translation adjustments	—			11
Investment in projects	231			378
Discount/premium on notes	2			5
Deferred financing costs	2			2
Discontinued operations	—			6
Total deferred tax liabilities	265			433
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	141			256
Difference between book and tax basis of property	596			530
Goodwill	38			83
Differences between book and tax basis of contracts	68			60
Pension and other postretirement benefits	74			122
Equity compensation	10			11
Bad debt reserve	14			12
U.S. capital loss carryforwards	1			1
U.S. Federal net operating loss carryforwards	596			728
Foreign net operating loss carryforwards	66			63
State net operating loss carryforwards	140			106
Foreign capital loss carryforwards	1			1
Federal and state tax credit carryforwards	376			446
Federal benefit on state uncertain tax positions	7			12
Intangibles amortization (excluding goodwill)	101			115
Derivatives, net	—			106
Inventory obsolescence	12			5
Other	—			7
Discontinued operations	—			2,093
Total deferred tax assets	2,241			4,757
Valuation allowance	(1,863		)	(2,032		)
Discontinued operations	—			(2,087		)
Total deferred tax assets, net of valuation allowance	378			638
Net deferred tax asset	$	113		$	205

Summary of NRG's net deferred tax position

The following table summarizes NRG's net deferred tax position:



	As of December 31,
	2017			2016
	(In millions)
Net deferred tax asset — noncurrent	$	134		$	225
Net deferred tax liability — noncurrent	(21		)	(20		)
Net deferred tax asset	$	113		$	205

Reconciliation of total amounts of uncertain tax benefits

The following table reconciles the total amounts of uncertain tax benefits:



	As of December 31,
	2017			2016
	(In millions)
Balance as of January 1	$	34		$	32
Increase due to current year positions	4			8
Decrease due to prior year positions	(8		)	—
Decrease due to settlements and payments	—			(6		)
Uncertain tax benefits as of December 31	$	30		$	34

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Summary of Company's NQSO activity, and changes during the year

The following table summarizes the Company's NQSO activity and changes during the year:



	Shares^(a)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
					(In years)	(In millions)
Outstanding at December 31, 2016	1,522,919		$	25.03	3	$	—
Forfeited	(50,001	)	29.35
Exercised	(187,060	)	20.71
Outstanding at December 31, 2017	1,285,858		25.49		3	6
Exercisable at December 31, 2017	1,285,858		25.49		3	6

(a) As of December 31, 2017, 51,207 NQSOs granted to employees of GenOn remain outstanding and exercisable.

Summary of 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,
	2017		2016		2015
	(In millions)
Total intrinsic value of options exercised	$	1	$	—	$	2
Cash received from options exercised	4		—		9

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^(a)		Weighted Average Grant-Date Fair Value per Unit
Non-vested at December 31, 2016	1,980,141		$	19.29
Granted	1,247,075		12.44
Forfeited	(176,132	)	14.98
Vested	(673,271	)	23.65
Non-vested at December 31, 2017	2,377,813		14.63

(a) As of December 31, 2017, 20,822 RSUs granted to GenOn employees remain outstanding.

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^(a)		Weighted Average Grant-Date Fair Value per Unit
Outstanding at December 31, 2016	453,674		$	21.54
Granted	120,251		16.76
Converted to Common Stock	(146,777	)	17.62
Outstanding at December 31, 2017	427,148		21.54

Summary of Company's outstanding DSU awards and changes during the year

The following table summarizes the Company's non-vested PSU awards and changes during the year:



	Units^(a)		Weighted Average Grant-Date Fair Value per Unit
Non-vested at December 31, 2016	1,282,588		$	21.47
Granted	738,830		15.91
Forfeited	(162,597	)	31.85
Non-vested at December 31, 2017	1,858,821		18.27

(a) There were no PSUs granted to GenOn employees and outstanding as of December 31, 2017.

Schedule of Share-based Payment Awards, Market Unit Valuation Assumptions

Significant assumptions used in the fair value model with respect to the Company's PSUs are summarized below:



	2017		2016
	RPSUs		MSUs
Expected volatility	43.96	%	34.33	%
Expected term (in years)	3		3
Risk free rate	1.5	%	1.31	%

Summary of NRG's total compensation expense recognized and total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized



										Non-vested Compensation Cost
	Compensation Expense									Unrecognized Total Cost		Weighted Average Recognition Period Remaining (In years)
	Year Ended December 31,									As of December 31,
Award	2017			2016			2015			2017		2017
	(In millions, except weighted average data)
NQSOs^(a)	$	—		$	—		$	—		$	—	—
RSUs	17			13			22			13		1.37
DSUs	2			2			2			—		—
MSUs	6			3			16			4		0.82
RPSUs	4			—			—			6		1.99
PRSUs^(b)	15			5			—			14		1.51
Total^(c)	$	44		$	23		$	40		$	37
Tax detriment recognized	$	(5	)	$	(4	)	$	(12	)

(a) All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2017, 2016, and 2015.

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Summary of NRG's material related-party transactions with affiliates



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	3	$	2	$	4
GenConn	5		5		4
Total	$	8	$	7	$	8

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

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, 2017 are as follows:



Period	(In millions)
2018	$	1
2019	1
2020	1
2021	3
2022	6
Thereafter	228
Total	$	240

Future minimum lease commitments under operating leases for the years ending after December 31, 2017 are as follows:



Period	(In millions)
2018	$	78
2019	80
2020	75
2021	65
2022	64
Thereafter	479
Total ^(a)	$	841

(a) Amounts in the table exclude future sublease income of $49 million associated with long-term leases for office locations.

Commitments under coal, gas and transportation contractual agreements

As of December 31, 2017, the Company's commitments under such outstanding agreements are as follows:



Period	(In millions)
2018	$	527
2019	188
2020	150
2021	112
2022	103
Thereafter	296
Total	$	1,376

Minimum purchase commitment obligations under purchased power agreements

Minimum purchase commitment obligations are as follows as of December 31, 2017:



Period	(In millions)
2018	$	21
2019	14
2020	12
2021	11
2022	10
Thereafter	—
Total ^(a)	$	68


(a)	As of December 31, 2017, the maximum remaining term under any individual purchased power contract is five years.

Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2017

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,
	2017		2016		2015
	(In millions)
Interest paid, net of amount capitalized	$	868	$	890	$	924
Income taxes paid ^(a)	9		14		12
Non-cash investing and financing activities:
Additions/(decrease) to fixed assets for accrued capital expenditures	70		35		(44		)

(a) In 2017, income taxes paid of $11 million are offset by $2 million in income tax refunds. In 2015, income taxes paid of $13 million are offset by $1 million in income tax refunds.

Guarantees (Tables)

12 Months Ended

Dec. 31, 2017

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,
	2017
Guarantees	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2016 Total
	(In millions)
Letters of credit and surety bonds^(a)	$	1,467	$	66	$	7	$	93	$	1,633	$	1,837
Asset sales guarantee obligations	—		—		257		55		312		677
Other guarantees	—		32		—		613		645		253
Total guarantees	$	1,467	$	98	$	264	$	761	$	2,590	$	2,767


(a)	Excludes$92 million and $272 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn as of December 31, 2017 and 2016, respectively.

Jointly Owned Plants (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017	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	%	$	395	$	(207	)	$	7
Big Cajun II Unit 3, New Roads, LA	58.00	%	202		(132		)	—
Cedar Bayou Unit 4, Baytown, TX	50.00	%	215		(75		)	7
Keystone, Shelocta, PA	3.70	%	12		—			1
Conemaugh, New Florence, PA	3.72	%	14		—			1

Unaudited Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Summary of Unaudited Quarterly Financial Data

Summarized unaudited quarterly financial data is as follows:



	Quarter Ended
	2017
	December 31			September 30			June 30			March 31
	(In millions, except per share data)
Operating revenues	$	2,497		$	3,049		$	2,701		$	2,382
Operating (loss)/ income	(1,345		)	376			343			39
Net (loss)/income from continuing operations	(1,667		)	190			99			(170		)
Income/(loss) from discontinued operations	13			(27		)	(741		)	(34		)
Net (loss)/income	(1,655		)	163			(642		)	(203		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(120		)	(8		)	(16		)	(40		)
Net (loss)/income attributable to NRG Energy, Inc.	(1,535		)	171			(626		)	(163		)
(Loss)/income available to Common Stockholders	$	(1,535	)	$	171		$	(626	)	$	(163	)
Weighted average number of common shares outstanding — basic	317			317			316			316
Income/(loss) from discontinued operations per weighted average common share — basic	$	0.04		$	(0.09	)	$	(2.34	)	$	(0.11	)
Net (loss)/income per weighted average common share — basic	$	(4.84	)	$	0.54		$	(1.98	)	$	(0.52	)
Weighted average number of common shares outstanding — diluted	317			322			316			316
Income/(loss) from discontinued operations per weighted average common share — diluted	$	0.04		$	(0.08	)	$	(2.34	)	$	(0.11	)
Net (loss)/income per weighted average common share — diluted	$	(4.84	)	$	0.53		$	(1.98	)	$	(0.52	)



	Quarter Ended
	2016
	December 31				September 30				June 30				March 31
	(In millions, except per share data)
Operating revenues	$	2,184			$	3,421			$	2,248			$	2,659
Operating (loss)/income	(658		)	—	429			—	164				331
Net (loss)/income from continuing operations	(891		)		128				(163		)		(57		)
(Loss)/income from discontinued operations	(164		)		265				(113		)		104
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
(Loss)/income from discontinued operations per weighted average common share — basic	$	(0.52	)		$	0.84			$	(0.36	)		$	0.33
Net (loss)/income per weighted average common share — basic	$	(3.12	)		$	1.27			$	(0.61	)		$	0.24
Weighted average number of common shares outstanding — diluted	316				317				315				315
(Loss)/income from discontinued operations per weighted average common share — diluted	$	(0.52	)		$	0.84			$	(0.36	)		$	0.33
Net (loss)/income per weighted average common share — diluted	$	(3.12	)	—	$	1.27		—	$	(0.61	)	—	$	0.24

Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017:



Ace Energy, Inc.	New Genco GP, LLC	NRG Norwalk Harbor Operations Inc.
Allied Home Warranty GP LLC	Norwalk Power LLC	NRG Operating Services, Inc.
Allied Warranty LLC	NRG Advisory Services LLC	NRG Oswego Harbor Power Operations Inc.
Arthur Kill Power LLC	NRG Affiliate Services Inc.	NRG PacGen Inc.
Astoria Gas Turbine Power LLC	NRG Arthur Kill Operations Inc.	NRG Portable Power LLC
Bayou Cove Peaking Power, LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Power Marketing LLC
BidURenergy, Inc.	NRG Bayou Cove LLC	NRG Reliability Solutions LLC
Cabrillo Power I LLC	NRG Business Services LLC	NRG Renter's Protection LLC
Cabrillo Power II LLC	NRG Cabrillo Power Operations Inc.	NRG Retail LLC
Carbon Management Solutions LLC	NRG California Peaker Operations LLC	NRG Retail Northeast LLC
Cirro Group, Inc.	NRG Cedar Bayou Development Company, LLC	NRG Rockford Acquisition LLC
Cirro Energy Services, Inc.	NRG Connected Home LLC	NRG Saguaro Operations Inc.
Conemaugh Power LLC	NRG Connecticut Affiliate Services Inc.	NRG Security LLC
Connecticut Jet Power LLC	NRG Construction LLC	NRG Services Corporation
Cottonwood Development LLC	NRG Curtailment Solutions, Inc	NRG SimplySmart Solutions LLC
Cottonwood Energy Company LP	NRG Development Company Inc.	NRG South Central Affiliate Services Inc.
Cottonwood Generating Partners I LLC	NRG Devon Operations Inc.	NRG South Central Generating LLC
Cottonwood Generating Partners II LLC	NRG Dispatch Services LLC	NRG South Central Operations Inc.
Cottonwood Generating Partners III LLC	NRG Distributed Energy Resources Holdings LLC	NRG South Texas LP
Cottonwood Technology Partners LP	NRG Distributed Generation PR LLC	NRG SPV #1 LLC
Devon Power LLC	NRG Dunkirk Operations Inc.	NRG Texas C&I Supply LLC
Dunkirk Power LLC	NRG El Segundo Operations Inc.	NRG Texas Gregory LLC
Eastern Sierra Energy Company LLC	NRG Energy Efficiency-L LLC	NRG Texas Holding Inc.
El Segundo Power, LLC	NRG Energy Labor Services LLC	NRG Texas LLC
El Segundo Power II LLC	NRG ECOKAP Holdings LLC	NRG Texas Power LLC
Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Warranty Services LLC
Energy Choice Solutions LLC	NRG Energy Services International Inc.	NRG West Coast LLC
Energy Plus Holdings LLC	NRG Energy Services LLC	NRG Western Affiliate Services Inc.
Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	O'Brien Cogeneration, Inc. II
Energy Protection Insurance Company	NRG Greenco LLC	ONSITE Energy, Inc.
Everything Energy LLC	NRG Home & Business Solutions LLC	Oswego Harbor Power LLC
Forward Home Security, LLC	NRG Home Services LLC	Reliant Energy Northeast LLC
GCP Funding Company, LLC	NRG Home Solutions LLC	Reliant Energy Power Supply, LLC
Green Mountain Energy Company	NRG Home Solutions Product LLC	Reliant Energy Retail Holdings, LLC
Gregory Partners, LLC	NRG Homer City Services LLC	Reliant Energy Retail Services, LLC
Gregory Power Partners LLC	NRG Huntley Operations Inc.	RERH Holdings, LLC
Huntley Power LLC	NRG HQ DG LLC	Saguaro Power LLC
Independence Energy Alliance LLC	NRG Identity Protect LLC	Somerset Operations Inc.
Independence Energy Group LLC	NRG Ilion Limited Partnership	Somerset Power LLC
Independence Energy Natural Gas LLC	NRG Ilion LP LLC	Texas Genco GP, LLC
Indian River Operations Inc.	NRG International LLC	Texas Genco Holdings, Inc.
Indian River Power LLC	NRG Maintenance Services LLC	Texas Genco LP, LLC
Keystone Power LLC	NRG Mextrans Inc.	Texas Genco Services, LP
Langford Wind Power, LLC	NRG MidAtlantic Affiliate Services Inc.	US Retailers LLC
Louisiana Generating LLC	NRG Middletown Operations Inc.	Vienna Operations Inc.
Meriden Gas Turbines LLC	NRG Montville Operations Inc.	Vienna Power LLC
Middletown Power LLC	NRG New Roads Holdings LLC	WCP (Generation) Holdings LLC
Montville Power LLC	NRG North Central Operations Inc.	West Coast Power LLC
NEO Corporation	NRG Northeast Affiliate Services Inc.

Condensed Consolidating Statement of Operations

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2017



	Guarantor Subsidiaries				Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,182		—	$	3,699		—	$	—		$	(252	)	$	10,629
Operating Costs and Expenses
Cost of operations	5,373				2,353				59			(249		)	7,536
Depreciation and amortization	405				619				32			—			1,056
Impairment losses	1,463				246				—			—			1,709
Selling, general and administrative	371				146				393			(3		)	907
Reorganization costs	6				—				38			—			44
Development costs	—				49				18			—			67
Total operating costs and expenses	7,618				3,413				540			(252		)	11,319
Other income - affiliate	—				—				87			—			87
Gain on sale of assets	4				12				—			—			16
Operating (Loss)/Income	(432		)		298				(453		)	—			(587		)
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries	(1,162		)		(113		)		26			1,249			—
Equity in earnings/(losses) of unconsolidated affiliates	—				95				(4		)	(60		)	31
Impairment losses on investments	—				(75		)		(4		)	—			(79		)
Other income, net	9				17				12			—			38
Net loss on debt extinguishment	—				(4		)		(49		)	—			(53		)
Interest expense	(14		)		(424		)		(452		)	—			(890		)
Total other expense	(1,167		)		(504		)		(471		)	1,189			(953		)
Loss from Continuing Operations Before Income Taxes	(1,599		)		(206		)		(924		)	1,189			(1,540		)
Income tax (benefit)/expense	(598		)		(10		)		616			—			8
Loss from Continuing Operations	(1,001		)		(196		)		(1,540		)	1,189			(1,548		)
Loss from Discontinued Operations, net of income tax	—				(160		)		(629		)	—			(789		)
Net Loss	(1,001		)		(356		)		(2,169		)	1,189			(2,337		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	—				(108		)		(16		)	(60		)	(184		)
Net Loss Attributable to NRG Energy, Inc.	$	(1,001	)		$	(248	)		$	(2,153	)	$	1,249		$	(2,153	)


(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, 2016



	Guarantor Subsidiaries				Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,509		—	$	3,222		—	$	—		$	(219	)	$	10,512
Operating Costs and Expenses
Cost of operations	5,402				2,080				42			(223		)	7,301
Depreciation and amortization	565				581				26			—			1,172
Impairment losses	378				324				—			—			702
Selling, general and administrative	415				192				488			—			1,095
Development costs	—				59				30			—			89
Total operating costs and expenses	6,760				3,236				586			(223		)	10,359
Other income - affiliate	—				—				193			—			193
Loss on sale of assets	(1		)		—				(79		)	—			(80		)
Operating Income/(Loss)	748				(14		)		(472		)	4			266
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries	(176		)		(5		)		313			(132		)	—
Equity in earnings/(losses) of unconsolidated affiliates	5				36				(4		)	(10		)	27
Impairment losses on investments	—				(252		)		(16		)	—			(268		)
Other income, net	4				23				9			(2		)	34
Net loss on debt extinguishment	—				(4		)		(138		)	—			(142		)
Interest expense	(15		)		(396		)		(484		)	—			(895		)
Total other expense	(182		)		(598		)		(320		)	(144		)	(1,244		)
Income/(Loss) from Continuing Operations Before Income Taxes	566				(612		)		(792		)	(140		)	(978		)
Income tax (benefit)/expense	(1		)		7				(63		)	62			5
Income/(Loss) from Continuing Operations	567				(619		)		(729		)	(202		)	(983		)
Income from Discontinued Operations, net of income tax	—				81				11			—			92
Net Income/(Loss)	567				(538		)		(718		)	(202		)	(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.	$	567			$	(435	)		$	(774	)	$	(132	)	$	(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.			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	9,881		—	$	2,541		—	$	—		$	(94	)	$	12,328
Operating Costs and Expenses
Cost of operations	7,610				1,470				14			(94		)	9,000
Depreciation and amortization	751				580				20			—			1,351
Impairment losses	4,494				366				—			—			4,860
Selling, general and administrative	468				204				556			—			1,228
Development costs	—				61				93			—			154
Total operating costs and expenses	13,323				2,681				683			(94		)	16,593
Other income - affiliate	—				—				193			—			193
Gain on postretirement benefits curtailment	—				21				—			—			21
Operating Loss	(3,442		)		(119		)		(490		)	—			(4,051		)
Other (Expense)/Income
Equity in losses of consolidated subsidiaries	(109		)		(1		)		(2,800		)	2,910			—
Equity in earnings of unconsolidated affiliates	8				37				—			(9		)	36
Impairment losses on investments	—				(25		)		(31		)	—			(56		)
Other income, net	4				21				1			—			26
Loss on sale of equity-method investment	—				—				(14		)	—			(14		)
Net (loss)/gain on debt extinguishment	—				(9		)		19			—			10
Interest expense	(14		)		(366		)		(557		)	—			(937		)
Total other expense	(111		)		(343		)		(3,382		)	2,901			(935		)
Loss from Continuing Operations Before Income Taxes	(3,553		)		(462		)		(3,872		)	2,901			(4,986		)
Income tax (benefit)/expense	(1,104		)		(93		)		2,489			53			1,345
Loss from Continuing Operations	(2,449		)		(369		)		(6,361		)	2,848			(6,331		)
Loss/(income) from Discontinued Operations, net of income tax	—				(115		)		10			—			(105		)
Net Loss	(2,449		)		(484		)		(6,351		)	2,848			(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.	$	(2,449	)		$	(461	)		$	(6,382	)	$	2,910		$	(6,382	)


(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 (LOSS)/INCOME

For the Year Ended December 31, 2017



	Guarantor Subsidiaries				Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)				Eliminations^(a)			Consolidated Balance
	(In millions)
Net Loss	$	(1,001	)		$	(356	)		$	(2,169	)		$	1,189		$	(2,337	)
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain on derivatives, net	1				13				25				(26		)	13
Foreign currency translation adjustments, net	6				7				—				(1		)	12
Available-for-sale securities, net	—				—				(8		)		—			(8		)
Defined benefit plan, net	(24		)		29				41				—			46
Other comprehensive (loss)/income	(17		)		49				58				(27		)	63
Comprehensive Loss	(1,018		)		(307		)		(2,111		)		1,162			(2,274		)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			—	(103		)	—	(16		)	—	(60		)	(179		)
Comprehensive Loss Attributable to NRG Energy, Inc.	$	(1,018	)		$	(204	)		$	(2,095	)		$	1,222		$	(2,095	)


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

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)	$	567		$	(538	)		$	(718	)		$	(202	)	$	(891	)
Other Comprehensive Income, 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	34			(13		)		(51		)		33			3
Other comprehensive income	33			18				38				(51		)	38
Comprehensive Income/(Loss)	600			(520		)		(680		)		(253		)	(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.	600			(417		)	—	(736		)		(183		)	(736		)
Dividends for preferred shares	—			—				5			—	—			5
Gain on redemption of preferred shares	—			—				(78		)		—			(78		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	600		$	(417	)		$	(663	)		$	(183	)	$	(663	)


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

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	$	(2,449	)	$	(484	)	$	(6,351	)	$	2,848		$	(6,436	)
Other Comprehensive (Loss)/Income, net of tax
Unrealized (loss)/gain on derivatives, net	(8		)	(16		)	48			(39		)	(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	(30		)	(39		)	20			50			1
Comprehensive Loss	(2,479		)	(523		)	(6,331		)	2,898			(6,435		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest	—			(42		)	31			(62		)	(73		)
Comprehensive Loss Attributable to NRG Energy, Inc.	(2,479		)	(481		)	(6,362		)	2,960			(6,362		)
Dividends for preferred shares	—			—			20			—			20
Comprehensive Loss Available for Common Stockholders	$	(2,479	)	$	(481	)	$	(6,382	)	$	2,960		$	(6,382	)


(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, 2017



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries				NRG Energy, Inc.				Eliminations^(a)			Consolidated Balance
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	—		$	348			$	643			$	—		$	991
Funds deposited by counterparties	37			—				—				—			37
Restricted cash	4			504				—				—			508
Accounts receivable - trade	769			306				4				—			1,079
Inventory	339			193				—				—			532
Derivative instruments	625			80				9				(88		)	626
Cash collateral posted in support of energy risk management activities	170			1				—				—			171
Accounts receivable - affiliate	712			210				(129		)		(698		)	95
Current assets held-for-sale	8			107				—				—			115
Prepayments and other current assets	116			118				27				—			261
Total current assets	2,780			1,867				554				(786		)	4,415
Net Property, Plant and Equipment	2,527			11,169			—	238			—	(26		)	13,908
Other Assets
Investment in subsidiaries	(106		)	28			—	7,581				(7,503		)	—
Equity investments in affiliates	—			1,036				2				—			1,038
Notes receivable, less current portion	—			2				36				(36		)	2
Goodwill	360			179				—				—			539
Intangible assets, net	458			1,291				—				(3		)	1,746
Nuclear decommissioning trust fund	692			—				—				—			692
Deferred income taxes	377			(7		)		(236		)		—			134
Derivative instruments	121			40				31				(20		)	172
Non-current assets held-for-sale	—			43				—				—			43
Other non-current assets	51			458				120				—			629
Total other assets	1,953			3,070				7,534				(7,562		)	4,995
Total Assets	$	7,260		$	16,106			$	8,326			$	(8,374	)	$	23,318
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	667			$	57			$	(36	)	$	688
Accounts payable	546			280				55				—			881
Accounts payable - affiliate	752			(202		)		181				(698		)	33
Derivative instruments	535			108				—				(88		)	555
Cash collateral received in support of energy risk management activities	37			—				—				—			37
Accrued interest expense	3			56				97				—			156
Current liabilities - held-for-sale	—			72				—				—			72
Other accrued expenses and other current liabilities	288			118				328				—			734
Other accrued expenses and other current liabilities - affiliate	—			—				161				—			161
Total current liabilities	2,161			1,099				879				(822		)	3,317
Other Liabilities
Long-term debt and capital leases	244			8,733				6,739				—			15,716
Nuclear decommissioning reserve	269			—				—				—			269
Nuclear decommissioning trust liability	415			—				—				—			415
Postretirement and other benefit obligations	118			1				339				—			458
Deferred income taxes	112			64				(155		)		—			21
Derivative instruments	110			107				—				(20		)	197
Out-of-market contracts, net	66			141				—				—			207
Non-current liabilities held-for-sale	—			8				—				—			8
Other non-current liabilities	295			317				52				—			664
Total non-current liabilities	1,629			9,371				6,975				(20		)	17,955
Total Liabilities	3,790			10,470				7,854				(842		)	21,272
Redeemable noncontrolling interest in subsidiaries	—			78				—				—			78
Stockholders' Equity	3,470			5,558				472				(7,532		)	1,968
Total Liabilities and Stockholders' Equity	$	7,260		$	16,106			$	8,326			$	(8,374	)	$	23,318


(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

ASSETS
Current Assets
Cash and cash equivalents	$	—		$	615			$	323			$	—		$	938
Funds deposited by counterparties	2			—				—				—			2
Restricted cash	11			435				—				—			446
Accounts receivable - trade	734			321				3				—			1,058
Inventory	482			239				—				—			721
Derivative instruments	962			196				1				(92		)	1,067
Cash collateral posted in support of energy risk management activities	116			34				—				—			150
Accounts receivable - affiliate	307			(254		)		200				(139		)	114
Current assets held-for-sale	—			9				—				—			9
Prepayments and other current assets	76			152				62				—			290
Current assets - discontinued operations	—			1,919				—				—			1,919
Total current assets	2,690			3,666				589				(231		)	6,714
Net Property, Plant and Equipment	4,219			10,926				251				(27		)	15,369
Other Assets
Investment in subsidiaries	1,090			145				10,128				(11,363		)	—
Equity investments in affiliates	(13		)	1,103				30				—			1,120
Notes receivable, less current portion	—			16				(76		)		76			16
Goodwill	359			303				—				—			662
Intangible assets, net	592			1,384				—				(3		)	1,973
Nuclear decommissioning trust fund	610			—				—				—			610
Derivative instruments	144			44				36				(43		)	181
Deferred income taxes	3			—				222				—			225
Non-current assets held for sale	—			10				—				—			10
Other non-current assets	67			446				328				—			841
Non-current assets - discontinued operations	—			2,961				—				—			2,961
Total other assets	2,852			6,412				10,668				(11,333		)	8,599
Total Assets	$	9,761		$	21,004			$	11,508			$	(11,591	)	$	30,682
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	498			$	(58	)		$	76		$	516
Accounts payable	501			247				34				—			782
Accounts payable - affiliate	753			(443		)		(200		)		(79		)	31
Derivative instruments	947			237				—				(92		)	1,092
Cash collateral received in support of energy risk management activities	81			—				—				—			81
Accrued interest expense	3			54				123				—			180
Other accrued expenses and other current liabilities	313			155				342				—			810
Current liabilities - discontinued operations	—			1,210				—				—			1,210
Total current liabilities	2,598			1,958				241				(95		)	4,702
Other Liabilities
Long-term debt and capital leases	244			8,252				7,461				—			15,957
Nuclear decommissioning reserve	287			—				—				—			287
Nuclear decommissioning trust liability	339			—				—				—			339
Postretirement and other benefit obligations	113			122				275				—			510
Deferred income taxes	186			125				(291		)		—			20
Derivative instruments	157			170				—				(43		)	284
Out-of-market contracts, net	80			150				—				—			230
Non-current liabilities held-for-sale	—			11				—				—			11
Other non-current liabilities	283			309				74				—			666
Other non-current liabilities - discontinued operations	—			3,184				—				—			3,184
Total non-current liabilities	1,689			12,323				7,519				(43		)	21,488
Total Liabilities	4,287			14,281				7,760				(138		)	26,190
Redeemable noncontrolling interest in subsidiaries	—			46				—				—			46
Stockholders' Equity	5,474			6,677			—	3,748			—	(11,453		)	4,446
Total Liabilities and Stockholders' Equity	$	9,761		$	21,004			$	11,508			$	(11,591	)	$	30,682


(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, 2017



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance

Cash Flows from Operating Activities
Net loss	$	(1,001	)	$	(356	)	$	(2,169	)	$	1,189		$	(2,337	)
Loss from discontinued operations	—			(160		)	(629		)	—			(789		)
Net loss from continuing operations	(1,001		)	(196		)	(1,540		)	1,189			(1,548		)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in earnings and distributions from unconsolidated affiliates	—			5			4			46			55
Depreciation and amortization	405			619			32			—			1,056
Provision for bad debts	54			2			12			—			68
Amortization of nuclear fuel	51			—			—			—			51
Amortization of financing costs and debt discount/premiums	—			42			18			—			60
Adjustment for debt extinguishment	—			4			49			—			53
Amortization of intangibles and out-of-market contracts	27			81			—			—			108
Amortization of unearned equity compensation	—			—			35			—			35
Net gain on sale of assets and equity method investments	(18		)	(16		)	—			—			(34		)
Impairment losses	1,463			321			4			—			1,788
Changes in derivative instruments	(100		)	(69		)	24			(26		)	(171		)
Changes in deferred income taxes and liability for uncertain tax benefits	(300		)	69			322			—			91
Changes in collateral deposits in support of energy risk management activities	(98		)	18			—			—			(80		)
Proceeds from sale of emission allowances	25			—			—			—			25
Changes in nuclear decommissioning trust liability	11			—			—			—			11
Cash (used)/provided by changes in other working capital	(363		)	(164		)	1,593			(1,209		)	(143		)
Cash provided by continuing operations	156			716			553			—			1,425
Cash used by discontinued operations	—			(38		)	—			—			(38		)
Net Cash Provided by Operating Activities	156			678			553			—			1,387
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			94			(94		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(249		)	—			249			—
Intercompany dividends	—			—			129			(129		)	—
Acquisition of businesses, net of cash acquired	(14		)	(27		)	—			—			(41		)
Capital expenditures	(183		)	(906		)	(22		)	—			(1,111		)
Net cash proceeds from notes receivable	—			17			—			—			17
Proceeds from renewable energy grants	8			—			—			—			8
Proceeds from sale of emission allowances	66			—			—			—			66
Investments in nuclear decommissioning trust fund securities	(512		)	—			—			—			(512		)
Proceeds from sales of nuclear decommissioning trust fund securities	501			—			—			—			501
Proceeds from sale of assets, net	33			54			—			—			87
Investments in unconsolidated affiliates	—			(40		)	—			—			(40		)
Other	18			(6		)	—			—			12
Cash (used)/provided by continuing operations	(83		)	(1,157		)	201			26			(1,013		)
Cash used by discontinued operations	—			(53		)	—			—			(53		)
Net Cash (Used)/Provided by Investing Activities	(83		)	(1,210		)	201			26			(1,066		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(94		)	—			94			—
Payments from/(for) intercompany loans	(45		)	13			32			—			—
Acquisition of Drop Down Assets, net of cash acquired	—			—			249			(249		)	—
Intercompany dividends	—			(129		)	—			129			—
Payment of dividends to common and preferred stockholders	—			—			(38		)	—			(38		)
Net receipts from settlement of acquired derivatives that include financing elements	—			2			—			—			2
Payments for debt extinguishment costs	—			—			(42		)	—			(42		)
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—			95			—			—			95
Payments from issuance of common stock	—			—			(2		)	—			(2		)
Proceeds from issuance of long-term debt	—			1,186			1,084			—			2,270
Payment of debt issuance and hedging costs	—			(47		)	(16		)	—			(63		)
Payments for short and long-term debt	—			(647		)	(1,701		)	—			(2,348		)
Receivable from affiliate	—			(125		)	—			—			(125		)
Other	—			(10		)	—			—			(10		)
Cash provided/(used) by continuing operations	(45		)	244			(434		)	(26		)	(261		)
Cash used by discontinued operations	—			(224		)	—			—			(224		)
Net Cash Provided/(Used) by Financing Activities	(45		)	20			(434		)	(26		)	(485		)
Effect of exchange rate changes on cash and cash equivalents	—			(1		)	—			—			(1		)
Change in cash from discontinued operations	—			(315		)	—			—			(315		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	28			(198		)	320			—			150
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	13			1,050			323			—			1,386
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	41		$	852		$	643		$	—		$	1,536


(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)	$	567		$	(538	)	$	(718	)	$	(202	)	$	(891	)
Income from discontinued operations	—			81			11			—			92
Net income/(loss) from continuing operations	567			(619		)	(729		)	(202		)	(983		)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distribution of unconsolidated affiliates	(5		)	52			5			2			54
Depreciation and amortization	565			581			26			—			1,172
Provision for bad debts	41			7			—			—			48
Amortization of nuclear fuel	49			—			—			—			49
Amortization of financing costs and debt discount/premiums	—			34			21			—			55
Adjustment for debt extinguishment	—			4			138			—			142
Amortization of intangibles and out-of-market contracts	39			128			—			—			167
Amortization of unearned equity compensation	—			—			10			—			10
Net loss on sale of assets and equity method investments, net	—			—			70			—			70
Impairment losses	378			578			16			—			972
Changes in derivative instruments	(77		)	145			(36		)	—			32
Changes in deferred income taxes and liability for uncertain tax benefits	(1		)	18			(60		)	—			(43		)
Changes in collateral deposits in support of energy risk management activities	437			(39		)	—			—			398
Proceeds from sale of emission allowances	34			—			—			—			34
Changes in nuclear decommissioning trust liability	41			—			—			—			41
Cash (used)/provided by changes in other working capital	(1,815		)	417			1,187			200			(11		)
Cash provided by continuing operations	253			1,306			648			—			2,207
Cash used by discontinued operations	—			(119		)	—			—			(119		)
Net Cash Provided by Operating Activities	253			1,187			648			—			2,088
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			81			(81		)	—
Intercompany dividends	—			—			12			(12		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(77		)	—			77			—
Acquisition of businesses, net of cash acquired	—			(209		)	—			—			(209		)
Capital expenditures	(180		)	(748		)	(48		)	—			(976		)
Net cash proceeds from 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 fund securities	(551		)	—			—			—			(551		)
Proceeds from sales of nuclear decommissioning trust fund securities	510			—			—			—			510
Proceeds from sale of assets, net	—			56			17			—			73
Investments in unconsolidated affiliates	3			(26		)	—			—			(23		)
Other	27			—			8			—			35
Cash (used)/provided by continuing operations	(192		)	(951		)	70			(16		)	(1,089		)
Cash provided by discontinued operations	—			297			—			—			297
Net Cash (Used)/Provided by Investing Activities	(192		)	(654		)	70			(16		)	(792		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(81		)	—			81			—
Intercompany dividends	(52		)	40			—			12			—
Payments (for)/from intercompany loans	(52		)	(49		)	101			—			—
Acquisition of Drop Down Assets, net of cash acquired	—			—			77			(77		)	—
Payment of dividends to common and preferred stockholders	—			—			(76		)	—			(76		)
Net receipts from settlement of acquired derivatives that include financing elements	—			6			—			—			6
Payment for preferred shares	—			—			(226		)	—			(226		)
Payments for debt extinguishment costs	—			—			(121		)	—			(121		)
Distributions from, net of contributions to, noncontrolling interest 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
Payment of debt issuance and hedging costs	—			(29		)	(60		)	—			(89		)
Payments for short and long-term debt	(1		)	(983		)	(4,924		)	—			(5,908		)
Other	(3		)	(10		)	—			—			(13		)
Cash (used)/provided by continuing operations	(108		)	125			(1,088		)	16			(1,055		)
Cash provided by discontinued operations	—			140			—			—			140
Net Cash (Used)/Provided by Financing Activities	(108		)	265			(1,088		)	16			(915		)
Effect of exchange rate changes on cash and cash equivalents	—			1			—			—			1
Change in cash from discontinued operations	—			318			—			—			318
Net (Decrease)/Increase in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	(47		)	481			(370		)	—			64
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	60			569			693			—			1,322
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	13		$	1,050		$	323		$	—		$	1,386

(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. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net loss	$	(2,449	)	$	(484	)	$	(6,351	)	$	2,848		$	(6,436	)
(Loss)/income from discontinued operations	—			(115		)	10			—			(105		)
Net loss from continuing operations	(2,449		)	(369		)	(6,361		)	2,848			(6,331		)
Adjustments to reconcile net loss to net cash (used)/provided by operating activities:
Equity in earnings and distribution of unconsolidated affiliates	(5		)	54			—			(12		)	37
Depreciation and amortization	751			580			20			—			1,351
Provision for bad debts	58			3			3			—			64
Amortization of nuclear fuel	45			—			—			—			45
Amortization of financing costs and debt discount/premiums	—			21			26			—			47
Adjustment for debt extinguishment	—			9			(19		)	—			(10		)
Amortization of intangibles and out-of-market contracts	52			99			—			—			151
Amortization of unearned equity compensation	—			(2		)	41			—			39
Net loss on sale of assets and equity method investments	—			—			14			—			14
Gain on post retirement benefits curtailment	—			(21		)	—			—			(21		)
Impairment losses	4,494			391			31			—			4,916
Changes in derivative instruments	264			(29		)	—			—			235
Changes in deferred income taxes and liability for uncertain tax benefits	(1,092		)	(237		)	2,655			—			1,326
Changes in collateral deposits in support of energy risk management activities	(323		)	(11		)	—			—			(334		)
Proceeds from sale of emission allowances	(24		)	—			—			—			(24		)
Changes in nuclear decommissioning trust liability	(2		)	—			—			—			(2		)
Cash (used)/provided by changes in other working capital	(8,656		)	(907		)	12,183			(2,836		)	(216		)
Cash (used)/provided by continuing operations	(6,887		)	(419		)	8,593			—			1,287
Cash provided by discontinued operations	—			62			—			—			62
Net Cash (Used)/Provided by Operating Activities	(6,887		)	(357		)	8,593			—			1,349
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			70			(70		)	—
Intercompany dividends	—			—			33			(33		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(698		)	—			698			—
Acquisition of business, net of cash acquired	—			(31		)	—			—			(31		)
Capital expenditures	(316		)	(654		)	(59		)	—			(1,029		)
Net cash proceeds from notes receivable	—			18			—			—			18
Proceeds from renewable energy grants	—			82			—			—			82
Proceeds from emission allowances, net of purchases	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	—			16			—			—			16
Cash (used)/provided by continuing operations	(272		)	(1,623		)	31			595			(1,269		)
Cash used by discontinued operations	—			(259		)	—			—			(259		)
Net Cash (Used)/Provided by Investing Activities	(272		)	(1,882		)	31			595			(1,528		)
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 Drop Down Assets, net of cash acquired	—			—			698			(698		)	—
Payment of dividends to common and preferred stockholders	—			—			(201		)	—			(201		)
Net receipts from settlement of acquired derivatives that include financing elements	—			14			—			—			14
Payment for treasury stock	—			—			(437		)	—			(437		)
Distributions from, net of contributions to, noncontrolling interest 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
Payment of debt issuance and hedging costs	—			(21		)	—			—			(21		)
Payments for short and long-term debt	—			(1,116		)	(246		)	—			(1,362		)
Other	—			(22		)	—			—			(22		)
Cash provided/(used) by continuing operations	7,183			1,610			(8,575		)	(595		)	(377		)
Cash used by discontinued operations	—			(55		)	—			—			(55		)
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
Change in cash from discontinued operations	—			(252		)	—			—			(252		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	24			(422		)	49			—			(349		)
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	36			991			644			—			1,671
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	60		$	569		$	693		$	—		$	1,322

(a) All significant intercompany transactions have been eliminated in consolidation.

VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Dec. 31, 2017

Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2017, 2016, and 2015



	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, 2017	$	29	$	56		$	—		$	(57	)	^(a)	$	28
Year Ended December 31, 2016	21		47			—			(39		)	^(a)	29
Year Ended December 31, 2015	21		62			—			(62		)	^(a)	21
Income tax valuation allowance, deducted from deferred tax assets^(b)
Year Ended December 31, 2017	$	4,116	$	(151	)	$	(15	)	$	(2,087	)	^(c)	$	1,863
Year Ended December 31, 2016	3,575		306			235			—				4,116
Year Ended December 31, 2015	265		3,039			271			—				3,575


(a)	Represents principally net amounts charged as uncollectible.


(b)	Includes income tax valuation allowance deducted from deferred tax assets recorded as discontinued operations, which amounted to $2,087 million and $2,194 million as of December 31, 2016 and 2015, respectively.


(c)	Represents deconsolidation of GenOn due to its petition for bankruptcy on June 14, 2017.

Nature of Business (Details)	3 Months Ended	12 Months Ended
Nature of Business (Details)	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)	Jun. 14, 2017 USD ($)
Power Generation Facilities
Generation capacity (in MW) \| MW		30,000
Discontinued Operations \| GenOn
Power Generation Facilities
Investment in GenOn recorded under cost method at fair value				$ 0
Loss on deconsolidation	$ 208,000,000	$ 634,000,000	$ 0

Nature of Business - Transformation Plan (Details) $ in Millions		42 Months Ended
	Jul. 12, 2017 USD ($) MW	Dec. 31, 2020 USD ($)	Dec. 31, 2017 MW
Restructuring Cost and Reserve [Line Items]
Generation capacity (in MW) \| MW			30,000
Transformation Plan
Restructuring Cost and Reserve [Line Items]
Term of plan	3 years
Transformation Plan \| Scenario, Forecast
Restructuring Cost and Reserve [Line Items]
Non-recurring working capital improvements		$ 370
Costs expected to be spent		$ 290
Transformation Plan \| Operations and Cost Excellence
Restructuring Cost and Reserve [Line Items]
Cost savings	$ 1,065
Transformation Plan \| Operations and Cost Excellence \| Annual Cost Savings
Restructuring Cost and Reserve [Line Items]
Cost savings	590
Transformation Plan \| Operations and Cost Excellence \| Net Margin Enhancement Program
Restructuring Cost and Reserve [Line Items]
Cost savings	215
Transformation Plan \| Operations and Cost Excellence \| Annual Reduction in Maintenance Capital Expenditures
Restructuring Cost and Reserve [Line Items]
Cost savings	50
Transformation Plan \| Operations and Cost Excellence \| Permanent Selling General and Administrative Reduction Associated with Asset Sales
Restructuring Cost and Reserve [Line Items]
Cost savings	$ 210
Transformation Plan \| Portfolio Optimization
Restructuring Cost and Reserve [Line Items]
Generation capacity (in MW) \| MW	6
Transformation Plan \| Portfolio Optimization \| Maximum
Restructuring Cost and Reserve [Line Items]
Effect on cash flows	$ 3,200
Transformation Plan \| Portfolio Optimization \| NRG Yield, Inc.
Restructuring Cost and Reserve [Line Items]
Ownership interest, percentage	100.00%
Transformation Plan \| Capital Structure and Allocation Enhancements
Restructuring Cost and Reserve [Line Items]
Effect on cash flows	$ 5,300
Reduction in consolidated debt, original amount	19,500
Reduction in consolidated debt	18,000
Consolidated debt original amount reduction	6,500
Consolidated debt, net amount reduction	$ 6,000
Corporate net debt to EBITDA ratio	3.0

Nature of Business (Yield IPO) (Details 2) - NRG Yield, Inc.	12 Months Ended
	Dec. 31, 2017
NRG
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Common stock, voting interest	0.551
Limited partnership, ownership interest	46.30%
Public Shareholders
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Common stock, voting interest	0.449
Limited partnership, ownership interest	53.70%

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Funds Deposited by Counterparties
Number of months beyond which company can not predict the holding of collateral (in months)	12 months
Collateral received from GenOn		$ 79
Accounts Receivable, Net [Abstract]
Allowance for doubtful accounts	$ 28	29
Project Development Costs and Capitalized Interest
Amount of interest capitalized	34	30	$ 25
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, accumulated amortization	$ 1,818	1,688
Income Taxes
Unrecognized tax benefits, more-likely-than-not threshold percentage	50.00%
Revenue Recognition
Energy revenues from resales of purchased power	$ 187	154	165
Unbilled revenues	376	321	307
Leases [Abstract]
Contingent rental income	879	912	753
Gross Receipts and Sales Taxes
Gross Receipts Tax	92	101	110
Cost of Energy for Retail Operations
Transmission and distribution charges not yet billed	107	90	85
Foreign Currency Translation and Transaction Gains and Losses
Cumulative translation adjustment	(2)	(11)	(10)
Marketing and Advertising Expense
Marketing and advertising expense	184	247	309
Advertising Expense	42	$ 53	$ 135
Reorganization Costs
Severance Costs	$ 44
South Texas Project
Property, Plant and Equipment
Ownership Interest (as a percent)	44.00%

Summary of Significant Accounting Policies - Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Cash and cash equivalents	$ 991	$ 938	$ 853
Funds deposited by counterparties	37	2	55
Restricted cash	508	446	414
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	1,536	$ 1,386	$ 1,322	$ 1,671
Current Debt Service Payment
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	51
Operating Expense
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	65
Distributions
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	57
Reserves
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 335

Summary of Significant Accounting Policies - Redeemable Non Controlling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Noncontrolling Interest [Line Items]
Balance at beginning of period	$ 46	$ 29	$ 19
Cash contributions from redeemable noncontrolling interest	99	33	27
Distributions to redeemable noncontrolling interest	(65)	(158)	(159)
Comprehensive loss attributable to redeemable noncontrolling interest	(72)	(38)	(17)
Balance at end of period	78	46	$ 29
Redeemable noncontrolling interest
Noncontrolling Interest [Line Items]
Distributions to redeemable noncontrolling interest	(2)	(1)
Non-cash adjustments to redeemable noncontrolling interest	$ 7	$ 23

Summary of Significant Accounting Policies - Recent Accounting Developments - Guidance Adopted in 2017 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase (decrease) in cash flows from operations	$ 1,387	$ 2,088	$ 1,349
Increase (decrease) in cash flows from investing	(1,066)	(792)	(1,528)
Adjustment for adoption of accounting pronouncements	(257)
Decrease in cash flows from financing	485	915	432
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of accounting pronouncements	(286)
Accounting Standards Update 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification from AOCI to retained earnings tax effect	$ 13
Accounting Standards Update 2016-18
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase (decrease) in cash flows from operations		(53)	37
Increase (decrease) in cash flows from investing		32	(43)
Adoption of ASU 2016-16 \| Noncurrent Assets
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of accounting pronouncements		267
Adoption of ASU 2016-16 \| Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of accounting pronouncements		(267)
Accounting Standards Update 2016-15 \| New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase (decrease) in cash flows from operations		$ 121
Decrease in cash flows from financing			$ 121

Discontinued Operations, Acquisitions and Dispositions - Summary of Results (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$ 13	$ (27)	$ (741)	$ (34)	$ (164)	$ 265	$ (113)	$ 104	$ (789)	$ 92	$ (105)
GenOn \| Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues									646	1,862
Operating costs and expenses									(702)	(1,896)
Gain on sale of assets									0	294
Other expenses									(98)	(168)
(Loss)/Income from operations of discontinued components, before tax									(154)	92
Income tax expense									9	11
(Loss)/Income from operations of discontinued components									(163)	81
Interest income - affiliate									8	11
(Loss)/Income from operations of discontinued components, net of tax									(155)	92
Pre-tax loss on deconsolidation									(208)	0
Settlement consideration and services credit									(289)	0
Pension and post-retirement liability assumption									(131)	0
Other									(6)	0
Loss on disposal of discontinued components, net of tax			$ (208)						(634)	0
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent									$ (789)	$ 92

Discontinued Operations, Acquisitions and Dispositions - Major Classes of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other current assets	$ 0	$ 1,919
Current assets - discontinued operations	115	9
Other non-current assets	43	10
Non-current assets - discontinued operations	0	2,961
Current liabilities - discontinued operations	0	1,210
Other non-current liabilities	0	3,184
Non-current liabilities - discontinued operations	$ 8	11
GenOn \| Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and cash equivalents		1,034
Other current assets		885
Current assets - discontinued operations		1,919
Property, plant and equipment, net		2,543
Other non-current assets		418
Non-current assets - discontinued operations		2,961
Current portion of long term debt and capital leases		704
Other current liabilities		506
Current liabilities - discontinued operations		1,210
Long-term debt and capital leases		2,050
Out-of-market contracts		811
Other non-current liabilities		323
Non-current liabilities - discontinued operations		$ 3,184

Discontinued Operations, Acquisitions and Dispositions - Discontinued Operations (Details) - USD ($) $ in Millions			1 Months Ended	7 Months Ended	12 Months Ended
	Jun. 14, 2017	Jun. 12, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other income - affiliate			$ 84.0		$ 87.0	$ 193.0	$ 193.0
Receivable from affiliate					125.0	0.0	$ 0.0
Long-term debt			$ 16,633.0	$ 16,633.0	$ 16,633.0	16,704.0
GenOn \| Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term debt	$ 2,500.0
Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Aggregate principal percentage threshold			93.00%	93.00%	93.00%
Amount due from GenOn			$ 125.0	$ 125.0	$ 125.0
Amount of pension liability future contributions			13.0	13.0	13.0			$ 13.0
GenOn
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pension liability retained			92.0	92.0	92.0	$ 120.0
Liability retained other post-employment and retiree health and welfare benefits			25.0	25.0	25.0
GenOn \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amount of pension liability future contributions								$ 13.0
Services Agreement \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Credit applied		$ 28.0	3.5		28.0
Receivable from affiliate			15.0
Shared services annualized rate		$ 84.0	84.0	84.0	84.0
Monthly cost of shared services	$ 5.0		7.0	5.0
GenOn \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Costs expected to be spent			261.3	261.3	261.3
Liability for estimated pension benefit obligations			92.0	92.0	92.0
GenOn \| Settlement Consideration \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Due to Affiliate			261.3	261.3	261.3
GenOn \| Services Agreement \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Due to Affiliate			$ 28.0	$ 28.0	$ 28.0
GenOn Senior Notes Due in 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest rate, stated percentage	7.875%
GenOn senior notes, due 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest rate, stated percentage	9.50%
GenOn senior notes, due 2020
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest rate, stated percentage	9.875%
GenOn Americas Generation Senior Notes Due in 2021
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest rate, stated percentage	8.50%
GenOn Americas Generation senior notes, due 2031
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest rate, stated percentage	9.125%

Discontinued Operations, Acquisitions and Dispositions - Dispositions of Majority Interest in EVgo (Details) $ in Millions		3 Months Ended	12 Months Ended
	Jun. 17, 2016 USD ($) charging_station parking_space	Jun. 30, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale			$ (34.0)	$ 70.0	$ 14.0
Equity method investments			1,038.0	$ 1,120.0
Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations \| EVgo
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration	$ 39.0
Cash received	17.0
Working capital adjustments	2.5
Capital contributions	15.0
Future capital contributions	7.0
Future earnout potential	70.0
Financial obligations under agreement	$ 102.5
Number of public fast charging Freedom stations \| charging_station	200
Number of commercial and multiifamily parking spaces \| parking_space	10,000
Loss on sale		$ 78.0
Loss on sale of equity the interest		$ 27.0
Remaining obligation	$ 56.0		$ 25.0
Remainin ownership interest			35.00%
Equity method investments			$ 1.0

Discontinued Operations, Acquisitions and Dispositions - Rockford Disposition (Details) $ in Millions			3 Months Ended	12 Months Ended
	Jul. 12, 2016 USD ($)	May 12, 2016 USD ($) MW	Jun. 30, 2016 USD ($)	Dec. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) \| MW				30,000
Impairment losses				$ 1,709	$ 702	$ 4,860
Rockford
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of ownership interest		100.00%
Impairment losses					$ 17
Proceeds from sale		$ 55
Discontinued Operations, Held-for-sale or Disposed of by Sale \| Rockford
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of ownership interest		100.00%
Cash consideration		$ 55
Generation capacity (in MW) \| MW		450
Impairment losses			$ 17
Proceeds from sale	$ 56
Base Residual Auction Results Adjustments	$ 1

Discontinued Operations, Acquisitions and Dispositions - Disposition of Altenex - 2015 (Details) - USD ($) $ in Millions		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Realized loss on equity method investment		$ 0	$ 0	$ 14
Discontinued Operations, Held-for-sale or Disposed of by Sale \| Altenex
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage	32.00%			32.00%
Cash consideration received	$ 26
Realized loss on equity method investment	$ 14

Discontinued Operations, Acquisitions and Dispositions - Acquisitions (Details) $ in Millions					3 Months Ended	12 Months Ended
	Nov. 09, 2016 USD ($)	Nov. 02, 2016 USD ($) MW	Oct. 03, 2016 USD ($) MW	Jun. 29, 2015 USD ($) MW	Dec. 31, 2016 USD ($)	Dec. 31, 2017 USD ($) MW
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW						30,000
Sun Edison Utility-Scale Solar and Wind
Business Acquisition [Line Items]
Cash consideration					$ 124
Purchase price					328
Current assets					5
Payments contingent upon future development milestones						$ 59
Amount paid for contingent consideration liability as of period end						20
SunEdison Solar Distributed Generation
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW			29
Cash consideration			$ 67
Purchase price allocated to construction in process			47
Purchase price allocated to intangible			15
Desert Sunlight
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW				550
Cash consideration				$ 285
Percentage of ownership interest				25.00%
Mechanically-complete Solar Assets \| Sun Edison Utility-Scale Solar and Wind
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW		530
In-development Wind Assets \| Sun Edison Utility-Scale Solar and Wind
Business Acquisition [Line Items]
Cash consideration		$ 111
Debt assumed					$ 222	$ 222
Remaining Lease Term					20 years
Construction-ready and in-development solar assets \| Sun Edison Utility-Scale Solar and Wind
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW						110
Cash consideration			2
In-development solar assets \| Sun Edison Utility-Scale Solar and Wind
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW						71
Construction-ready Solar Facility \| Sun Edison Utility-Scale Solar and Wind
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW						154
Cash consideration	$ 11
NRG \| Mechanically-complete Solar Assets \| Sun Edison Utility-Scale Solar and Wind
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW		265
Post-closing obligations \| SunEdison Solar Distributed Generation
Business Acquisition [Line Items]
Cash consideration			$ 5
Non Recourse Debt \| Utah Portfolio
Business Acquisition [Line Items]
Additional debt borrowed					$ 65	$ 65

Discontinued Operations, Acquisitions and Dispositions - Transfer of Assets Under Common Control (Details) $ in Millions	Dec. 31, 2017 USD ($) MW	Nov. 01, 2017 USD ($) MW	Aug. 01, 2017 USD ($) wind_project	Mar. 27, 2017 USD ($) MW	Dec. 31, 2016 USD ($)	Sep. 01, 2016 USD ($)	Nov. 03, 2015 USD ($) facility MW	Jan. 02, 2015 USD ($)
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW	30,000
Long-term debt	$ 16,633.0				$ 16,704.0
SPP
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW		38
Cash consideration		$ 71.0
Working capital adjustments		$ 3.0
NRG Wind TE Holdco
Business Acquisition [Line Items]
Cash consideration			$ 44.0
Working capital adjustments			$ 3.0
Percentage of ownership sold			25.00%
Number of projects sold \| wind_project			12
Agua Caliente Solar Project
Business Acquisition [Line Items]
Cash consideration				$ 130.0
Working capital adjustments				1.0
Debt assumed				$ 328.0
CVSR
Business Acquisition [Line Items]
Percentage of ownership sold						51.05%
Cash consideration received						$ 78.5
ROFO Assets
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW							814
Percentage of ownership sold							75.00%
Cash consideration received							$ 209.0	$ 489.0
Long-term debt							$ 193.0	737.0
Number of facilities \| facility							12
Cash consideration net of working capital adjustments							$ 207.0
NRG Yield, Inc. \| CVSR
Business Acquisition [Line Items]
Long-term debt						$ 496.0
Financial Institutions \| ROFO Assets
Business Acquisition [Line Items]
Noncontrolling interest							159.0
Working Capital Adjustment \| ROFO Assets
Business Acquisition [Line Items]
Cash consideration received							$ 2.0	$ 9.0
Agua Caliente \| Agua Caliente Solar Project
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW				46
Percentage of ownership sold				16.00%
Utah Portfolio \| Agua Caliente Solar Project
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW				265

Fair Value of Financial Instruments - Estimated Carrying Amounts of Fair Value of Financial Instruments not Carried at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Assets
Notes receivable	$ 16	$ 34
Liabilities
Long-term debt, including current portion	16,633	16,704
Level 2
Debt, Long-term and Short-term, Combined Amount [Abstract]
Long-term debt, including current portion	8,934	9,205
Level 3
Debt, Long-term and Short-term, Combined Amount [Abstract]
Long-term debt, including current portion	7,960	7,415
Carrying Amount
Assets
Notes receivable	16	34
Liabilities
Long-term debt, including current portion	16,603	16,655
Fair Value Measurement
Assets
Notes receivable	15	34
Liabilities
Long-term debt, including current portion	$ 16,894	$ 16,620

Fair Value of Financial Instruments - Assets and Liabilities Measured and Recorded at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	$ 798	$ 1,248
Derivative liabilities	752	1,376
Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	745	1,199
Derivative liabilities	693	1,288
Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	53	49
Derivative liabilities	59	88
Fair Value, Measurements, Recurring
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	19	17
Available-for-sale Securities	3	10
U.S. government and federal agency obligations	1	1
Total assets	1,513	1,886
Total liabilities	752	1,376
Fair Value, Measurements, Recurring \| Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	745	1,199
Derivative liabilities	693	1,288
Fair Value, Measurements, Recurring \| Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	53	49
Derivative liabilities	59	88
Fair Value, Measurements, Recurring \| Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	47	25
Fair Value, Measurements, Recurring \| U.S. government and federal agency obligations
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	43	73
Fair Value, Measurements, Recurring \| Federal agency mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	82	62
Fair Value, Measurements, Recurring \| Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	14	17
Fair Value, Measurements, Recurring \| Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	99	84
Fair Value, Measurements, Recurring \| Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	334	292
Investments, Fair Value Disclosure	68	54
Fair Value, Measurements, Recurring \| Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	5	3
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	3	10
U.S. government and federal agency obligations	1	1
Total assets	616	960
Total liabilities	257	494
Fair Value, Measurements, Recurring \| Level 1 \| Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	191	560
Derivative liabilities	257	494
Fair Value, Measurements, Recurring \| Level 1 \| Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	0	0
Derivative liabilities	0	0
Fair Value, Measurements, Recurring \| Level 1 \| Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	45	25
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):
Nuclear trust fund investments	42	72
Fair Value, Measurements, Recurring \| Level 1 \| Federal agency mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear 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):
Nuclear 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):
Nuclear 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):
Nuclear trust fund investments	334	292
Fair Value, Measurements, Recurring \| Level 1 \| Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear 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
U.S. government and federal agency obligations	0	0
Total assets	765	765
Total liabilities	418	724
Fair Value, Measurements, Recurring \| Level 2 \| Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	509	549
Derivative liabilities	359	636
Fair Value, Measurements, Recurring \| Level 2 \| Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	53	49
Derivative liabilities	59	88
Fair Value, Measurements, Recurring \| Level 2 \| Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	2	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):
Nuclear 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):
Nuclear trust fund investments	82	62
Fair Value, Measurements, Recurring \| Level 2 \| Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	14	17
Fair Value, Measurements, Recurring \| Level 2 \| Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	99	84
Fair Value, Measurements, Recurring \| Level 2 \| Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear 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):
Nuclear trust fund investments	5	3
Fair Value, Measurements, Recurring \| Level 3
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	19	17
Available-for-sale Securities	0	0
U.S. government and federal agency obligations	0	0
Total assets	64	107
Total liabilities	77	158
Fair Value, Measurements, Recurring \| Level 3 \| Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	45	90
Derivative liabilities	77	158
Fair Value, Measurements, Recurring \| Level 3 \| Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	0	0
Derivative liabilities	0	0
Fair Value, Measurements, Recurring \| Level 3 \| Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear 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):
Nuclear 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):
Nuclear 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):
Nuclear 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):
Nuclear 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):
Nuclear trust fund investments	0	0
Fair Value, Measurements, Recurring \| Level 3 \| Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	$ 0	$ 0

Fair Value of Financial Instruments - Reconciliation of Level 3 Financial Instruments (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ (51)	$ 49
Total gains/(losses) realized/unrealized:
Included in earnings	45	2
Included in nuclear decommissioning obligations	0	(1)
Purchases	(23)	(28)
Contracts reclassified to held-for-sale	4
Transfers into Level 3	(1)	(18)
Transfers out of Level 3	13	(55)
Ending balance	(13)	(51)
Gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held at the end of period	8	(13)
Debt Securities
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	17	17
Total gains/(losses) realized/unrealized:
Included in earnings	2	0
Included in nuclear decommissioning obligations	0	0
Purchases	0	0
Contracts reclassified to held-for-sale	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Ending balance	19	17
Gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held at the end of period	2	0
Trust Fund Investment
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	0	54
Total gains/(losses) realized/unrealized:
Included in earnings		0
Included in nuclear decommissioning obligations		(1)
Purchases		1
Transfers into Level 3		0
Transfers out of Level 3		(54)
Ending balance		0
Gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held at the end of period		0
Derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(68)	(22)
Total gains/(losses) realized/unrealized:
Included in earnings	43	2
Included in nuclear decommissioning obligations	0	0
Purchases	(23)	(29)
Contracts reclassified to held-for-sale	4
Transfers into Level 3	(1)	(18)
Transfers out of Level 3	13	(1)
Ending balance	(32)	(68)
Gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held at the end of period	$ 6	$ (13)

Fair Value of Financial Instruments - Derivative Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Total derivative assets valued with prices provided by models and other valuation techniques percentage	6.00%
Total derivative liabilities valued with prices provided by models and other valuation techniques, percentage	10.00%
Increase (decrease) in credit reserve		$ 10

Fair Value of Financial Instruments - Derivative Fair Value Measurement (Details) $ in Millions	Dec. 31, 2017 USD ($) $ / MWh	Dec. 31, 2016 USD ($) $ / MWh
Assets
Derivative assets	$ 798	$ 1,248
Liabilities
Derivative liabilities	752	1,376
Fair Value Inputs [Abstract]
Cash collateral posted in support of energy risk management activities	171	150
Cash collateral received in support of energy risk management activities	37	81
Commodity contracts
Assets
Derivative assets	745	1,199
Liabilities
Derivative liabilities	693	1,288
Fair Value Inputs [Abstract]
Cash collateral posted in support of energy risk management activities	73	13
Cash collateral received in support of energy risk management activities	11	13
Commodity contracts \| Fair Value, Measurements, Recurring
Assets
Derivative assets	745	1,199
Liabilities
Derivative liabilities	693	1,288
Commodity contracts \| Fair Value, Measurements, Recurring \| Level 3
Assets
Derivative assets	45	90
Liabilities
Derivative liabilities	77	158
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3
Assets
Derivative assets	34	39
Liabilities
Derivative liabilities	$ 65	$ 108
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3 \| Low
Fair Value Inputs [Abstract]
Forward Market Price (USD per MWh) \| $ / MWh	10	11
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3 \| High
Fair Value Inputs [Abstract]
Forward Market Price (USD per MWh) \| $ / MWh	142	104
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3 \| Weighted Average
Fair Value Inputs [Abstract]
Forward Market Price (USD per MWh) \| $ / MWh	33	31
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3
Assets
Derivative assets	$ 11	$ 51
Liabilities
Derivative liabilities	$ 12	$ 50
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3 \| Low
Fair Value Inputs [Abstract]
Auction Prices (USD per MWh) \| $ / MWh	(28)	(22)
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3 \| High
Fair Value Inputs [Abstract]
Auction Prices (USD per MWh) \| $ / MWh	46	17
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3 \| Weighted Average
Fair Value Inputs [Abstract]
Auction Prices (USD per MWh) \| $ / MWh	0	0

Fair Value of Financial Instruments - Counterparty Credit Risk (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Fair Value Meaurements and Concentration of Credit Risk
Counterparty credit exposure, excluding credit risk exposure under certain long term agreements	$ 220
Counterparty credit exposure, collateral held (cash and letters of credit) against positions	30
Counterparty credit exposure, net	$ 196
Company's exposure before collateral expected to roll off by the end of 2015 (as a percent)	73.00%
Net exposure (as a percent)	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	$ 37
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	$ 68	$ 48	$ 64
Investment grade
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	69.00%
Non-Investment grade/Non-Rated
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	31.00%
Financial Institutions
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	14.00%
Utilities, energy merchants, marketers and other
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	86.00%
NRG Yield, Inc.
Derivative Fair Value Meaurements and Concentration of Credit Risk
Estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements for the next 5 years	$ 2,600

Accounting for Derivative Instruments and Hedging Activities - Net Notional Volume Buy/Sell of Open Derivative Transactions (Details) shares in Millions, bbl in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) MWh MMBTU T shares bbl	Dec. 31, 2016 USD ($) MWh MMBTU T shares bbl
Long \| Emissions
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton) \| T	1	0
Long \| Coal
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton) \| T	21	35
Long \| Oil
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels) \| bbl	0	1
Long \| Power
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) \| MWh	14	7
Long \| Interest
Derivative [Line Items]
Derivative, notional amount (in usd) \| $	$ 3,876	$ 3,429
Long \| Equity
Derivative [Line Items]
Derivative, non-monetary notional amount (in shares) \| shares	1	1
Short \| Natural Gas
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) \| MMBTU	17	53
Short \| Capacity
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) \| MWh	1	1

Accounting for Derivative Instruments and Hedging Activities - Fair Value Within the Derivative Instrument Valuation (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative assets	$ 798	$ 1,248
Derivative liabilities	752	1,376
Designated as Hedging Instrument
Derivative [Line Items]
Derivative assets	12	12
Derivative liabilities	16	69
Designated as Hedging Instrument \| Interest rate contracts current
Derivative [Line Items]
Derivative assets	1	0
Derivative liabilities	5	28
Designated as Hedging Instrument \| Interest rate contracts long-term
Derivative [Line Items]
Derivative assets	11	12
Derivative liabilities	11	41
Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative assets	786	1,236
Derivative liabilities	736	1,307
Not Designated as Hedging Instrument \| Interest rate contracts current
Derivative [Line Items]
Derivative assets	9	0
Derivative liabilities	15	7
Not Designated as Hedging Instrument \| Interest rate contracts long-term
Derivative [Line Items]
Derivative assets	32	37
Derivative liabilities	28	12
Not Designated as Hedging Instrument \| Commodity contracts current
Derivative [Line Items]
Derivative assets	616	1,067
Derivative liabilities	535	1,057
Not Designated as Hedging Instrument \| Commodity contracts long-term
Derivative [Line Items]
Derivative assets	129	132
Derivative liabilities	$ 158	$ 231

Accounting for Derivative Instruments and Hedging Activities - Offsetting of Derivatives by Counterparty Master Agreement level and Collateral Received (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	$ 798	$ 1,248
Cash Collateral (Held)/Posted	(37)	(81)
Derivative liabilities	752	1,376
Cash collateral posted in support of energy risk management activities	171	150
Gross Amounts of Recognized Assets / Liabilities	46	(128)
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	62	0
Net Amount	108	(128)
Commodity contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	745	1,199
Derivative Instruments	(578)	(1,021)
Cash Collateral (Held)/Posted	(11)	(13)
Net Amount	156	165
Derivative liabilities	693	1,288
Derivative Instruments	578	1,021
Cash collateral posted in support of energy risk management activities	73	13
Net Amount	(42)	(254)
Gross Amounts of Recognized Assets / Liabilities	52	(89)
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	62	0
Net Amount	114	(89)
Interest rate contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	53	49
Derivative Instruments	(3)	(4)
Cash Collateral (Held)/Posted	0
Net Amount	50	45
Derivative liabilities	59	88
Derivative Instruments	3	4
Cash collateral posted in support of energy risk management activities	0	0
Net Amount	(56)	(84)
Gross Amounts of Recognized Assets / Liabilities	(6)	(39)
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	0	0
Net Amount	$ (6)	$ (39)

Accounting for Derivative Instruments and Hedging Activities - Effect of ASC 815 on Accumulated OCI Balance Attributable to Hedge Derivatives, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effect of ASC 815 on NRG's Accumulated OCI Balance Attributable to Cash Flow Hedge Derivatives
Accumulated OCI beginning balance	$ (66)	$ (101)	$ (68)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	12	21	15
Mark-to-market of cash flow hedge accounting contracts	0	14	(48)
Accumulated OCI ending balance, net of tax of $8, $16 and $16 in 2017, 2016 and 2015 respectively	(54)	(66)	(101)
Accumulated OCI ending balance, tax	8	16	16
Losses expected to be realized from other comprehensive loss during the next 12 months, net of $2 tax	(12)
Losses expected to be realized from other comprehensive loss during the next 12 months, tax	2
Interest Rate
Effect of ASC 815 on NRG's Accumulated OCI Balance Attributable to Cash Flow Hedge Derivatives
Accumulated OCI beginning balance	(66)	(101)	(67)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	12	21	14
Mark-to-market of cash flow hedge accounting contracts	0	14	(48)
Accumulated OCI ending balance, net of tax of $8, $16 and $16 in 2017, 2016 and 2015 respectively	(54)	(66)	(101)
Losses expected to be realized from other comprehensive loss during the next 12 months, net of $2 tax	$ (12)
Energy Commodities
Effect of ASC 815 on NRG's Accumulated OCI Balance Attributable to Cash Flow Hedge Derivatives
Accumulated OCI beginning balance		$ 0	(1)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts			1
Mark-to-market of cash flow hedge accounting contracts			0
Accumulated OCI ending balance, net of tax of $8, $16 and $16 in 2017, 2016 and 2015 respectively			$ 0

Accounting for Derivative Instruments and Hedging Activities - Pre-tax Effects of Economic Hedges not Designated as Cash Flow Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Unrealized Mark To Market Results [Abstract]
Reversal of previously recognized unrealized loss/(gains) on settled positions related to economic hedges	$ 47	$ (128)	$ (162)
Reversal of acquired gain positions related to economic hedges	0	(12)	(22)
Net unrealized gains/(losses) on open positions related to economic hedges	146	6	(9)
Total unrealized mark-to-market gains/(losses) for economic hedging activities	193	(134)	(193)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(25)	10	(46)
Reversal of acquired gain positions related to trading activity	0	0	(14)
Net unrealized gains/(losses) on open positions related to trading activity	14	18	(16)
Total unrealized mark-to-market (losses)/gains for trading activity	(11)	28	(76)
Total unrealized gains/(losses)	182	(106)	(269)
Credit Risk Related Contingent Features [Abstract]
Collateral required contracts with credit rating contingent features in a net liability position	4
Adequate Assurance Clauses
Credit Risk Related Contingent Features [Abstract]
Collateral required for contracts in net liability positions that have adequate assurance clauses	25
Credit Rating Contingent Features
Credit Risk Related Contingent Features [Abstract]
Collateral required for contracts in net liability positions that have adequate assurance clauses	7
Commodity contracts
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	182	(106)	(269)
Commodity contracts \| Operating revenue
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	228	(614)	(210)
Commodity contracts \| Cost of operations
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	(46)	508	(59)
Interest rate contracts
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	$ 9	$ 36	$ 17

Nuclear Decommissioning Trust Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Nuclear decommissioning trust fund disclosure
Fair Value	$ 692	$ 610
Unrealized Gains	276	217
Unrealized Losses	2	4
Proceeds from sales of available-for-sale securities and the related realized gains and losses
Realized gains	22	26	$ 21
Realized losses	8	11	14
Proceeds from sale of securities	501	510	$ 631
Cash and cash equivalents
Nuclear decommissioning trust fund disclosure
Fair Value	47	25
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	$ 43	$ 73
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	$ 82	$ 62
Unrealized Gains	1	1
Unrealized Losses	$ 1	$ 1
Weighted- average maturities (in years)	23 years	25 years
Commercial mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 13	$ 17
Unrealized Gains	0	0
Unrealized Losses	$ 0	$ 1
Weighted- average maturities (in years)	20 years	26 years
Corporate debt securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 99	$ 84
Unrealized Gains	2	1
Unrealized Losses	$ 1	$ 2
Weighted- average maturities (in years)	11 years	11 years
Equity securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 403	$ 346
Unrealized Gains	272	214
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	$ 5	$ 3
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) - USD ($) $ in Millions	12 Months Ended
Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Fuel oil	$ 90	$ 142
Coal/Lignite	126	219
Natural gas	24	28
Spare parts	292	332
Total Inventory	532	$ 721
Inventory Write-down	$ 33

Notes Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Notes receivable	$ 16	$ 34
Notes receivable, current	14	18
Notes receivable, noncurrent	$ 2	$ 16

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment
Total property, plant and equipment	$ 18,373	$ 20,705
Accumulated depreciation	(4,465)	(5,336)
Net Property, Plant and Equipment	13,908	15,369
Facilities and equipment
Property, Plant and Equipment
Total property, plant and equipment	$ 15,907	18,698
Facilities and equipment \| Low
Property, Plant and Equipment
Depreciable lives (in years)	1 year
Facilities and equipment \| Maximum
Property, Plant and Equipment
Depreciable lives (in years)	40 years
Land and improvements
Property, Plant and Equipment
Total property, plant and equipment	$ 710	750
Nuclear fuel
Property, Plant and Equipment
Total property, plant and equipment	$ 236	226
Depreciable lives (in years)	5 years
Office furnishings and equipment
Property, Plant and Equipment
Total property, plant and equipment	$ 434	412
Office furnishings and equipment \| Low
Property, Plant and Equipment
Depreciable lives (in years)	2 years
Office furnishings and equipment \| Maximum
Property, Plant and Equipment
Depreciable lives (in years)	10 years
Construction in progress
Property, Plant and Equipment
Total property, plant and equipment	$ 1,086	$ 619

Asset Impairments (Details) - USD ($)			1 Months Ended	3 Months Ended						12 Months Ended
Asset Impairments (Details) - USD ($)	May 12, 2016	Mar. 01, 2016	Nov. 30, 2014	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 14, 2017
Asset Impairments
Construction in progress						$ 0
Impairment losses										$ 1,709,000,000	$ 702,000,000	$ 4,860,000,000
Other impairment losses											48,000,000
Impairment losses on investments									$ 56,000,000	$ 79,000,000	268,000,000	56,000,000
Elbow Creek
Asset Impairments
Impairment losses							$ 117,000,000
Goat Wind
Asset Impairments
Impairment losses							60,000,000
Forward
Asset Impairments
Impairment losses							6,000,000
Long Beach
Asset Impairments
Impairment losses							36,000,000
Other
Asset Impairments
Impairment losses											153,000,000
Emission Allowances
Asset Impairments
Impairment losses											23,000,000
Other Intangible Assets
Asset Impairments
Impairment losses											23,000,000
Solar Panels
Asset Impairments
Impairment losses											19,000,000
Deferred Marketing Expenses
Asset Impairments
Impairment losses											18,000,000
Limestone
Asset Impairments
Impairment losses									1,514,000,000
W.A. Parish
Asset Impairments
Impairment losses									1,295,000,000
Huntley
Asset Impairments
Impairment losses												132,000,000
Term of agreement		4 years
Dunkirk
Asset Impairments
Impairment losses												160,000,000
Term of agreement			10 years
Gregory Power Partners, L.P.
Asset Impairments
Impairment losses												$ 176,000,000
Rockford
Asset Impairments
Impairment losses											17,000,000
Percentage of ownership interest	100.00%
Proceeds from sale	$ 55,000,000
Renewables
Asset Impairments
Impairment losses				$ 15,000,000	$ 14,000,000	22,000,000
Collectibility of Receivables \| BTEC New Albany, LLC
Asset Impairments
Loss contingency, receivable													$ 48,000,000
Collectibility of Receivables \| BTEC New Albany, LLC \| Purchaser Incurred Costs
Asset Impairments
Loss contingency, receivable													38,000,000
Collectibility of Receivables \| BTEC New Albany, LLC \| Liquidation Damages
Asset Impairments
Loss contingency, receivable													$ 10,000,000
Construction in Progress
Asset Impairments
Impairment losses						$ 41,000,000
South Texas Project
Asset Impairments
Impairment loss investments				1,248,000,000
Indian River
Asset Impairments
Impairment loss investments				36,000,000
Keystone
Asset Impairments
Impairment loss investments				35,000,000
Conemaugh
Asset Impairments
Impairment loss investments				35,000,000
Langford
Asset Impairments
Impairment loss investments				110,000,000
Elbow Creek
Asset Impairments
Impairment loss investments				26,000,000
Forward
Asset Impairments
Impairment loss investments				4,000,000
Petra Nova Parish Holdings
Asset Impairments
Impairment loss investments				$ 69,000,000				$ 140,000,000
Ownership percentage				50.00%				50.00%		50.00%
Other
Asset Impairments
Impairment loss investments				$ 11,000,000							$ 22,000,000
Community Wind North, LLC
Asset Impairments
Impairment loss investments							36,000,000
Sherbino I Wind Farm LLC
Asset Impairments
Impairment loss investments							$ 70,000,000
Solar Panels
Asset Impairments
Impairment losses									$ 29,000,000

Goodwill and Other Intangibles - Narrative (Details)	3 Months Ended	12 Months Ended
Goodwill and Other Intangibles - Narrative (Details)	Dec. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2006 USD ($)
Goodwill and Other Intangibles
Goodwill	$ 539,000,000	$ 539,000,000	$ 662,000,000
Goodwill deductible for U.S. income tax purposes	460,000,000	460,000,000	547,000,000
Impairment		26,000,000	64,000,000
Emission allowances held-for-sale	9,000,000	9,000,000
Out-of-market contracts, net	207,000,000	207,000,000	230,000,000
Accumulated amortization, out of market contracts	358,000,000	358,000,000	457,000,000
Emission Allowances
Goodwill and Other Intangibles
Impairment		20,000,000	23,000,000
PPA
Goodwill and Other Intangibles
Impairment		6,000,000	$ 0
Impairment related to power purchase agreements		6,000,000
Texas Genco
Goodwill and Other Intangibles
Goodwill in connection with acquisition					$ 1,700,000,000
EME Project Financings \| Lease Agreements
Goodwill and Other Intangibles
Out-of-market contracts, net	159,000,000	159,000,000
SPP
Goodwill and Other Intangibles
Goodwill	0	0
Goodwill, Impairment Loss	12,000,000
BETM \| Held-for-sale
Goodwill and Other Intangibles
Goodwill	21,000,000	21,000,000
Goodwill, Impairment Loss	$ 90,000,000
Texas
Goodwill and Other Intangibles
Goodwill, Impairment Loss		$ 337,000,000		$ 1,400,000,000
Percentage of carrying amount	0.43	0.43
EME Project Financings
Goodwill and Other Intangibles
Goodwill	$ 165,000,000	$ 165,000,000
Out-of-market contracts, net				$ 159,000,000
Retail
Goodwill and Other Intangibles
Goodwill	341,000,000	341,000,000
Other
Goodwill and Other Intangibles
Goodwill	33,000,000	33,000,000
Texas
Goodwill and Other Intangibles
Goodwill	$ 0	$ 0

Goodwill and Other Intangibles - Components of Intangible Assets Subject to Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	$ 3,661	$ 3,721
Purchases	63	47
Acquisition of businesses	18	18
Usage	(38)	(45)
Write-off of fully amortized balances	(77)	(10)
Impairment	(26)	(64)
Other	(37)	(6)
Balance at end of period	3,564	3,661
Less accumulated amortization	(1,818)	(1,688)
Net carrying amount	1,746	1,973
Emission Allowances
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	789	816
Purchases	31	13
Acquisition of businesses	0	0
Usage	(10)	(1)
Write-off of fully amortized balances	0	(10)
Impairment	(20)	(23)
Other	(23)	(6)
Balance at end of period	767	789
Less accumulated amortization	(591)	(518)
Net carrying amount	176	271
Energy Supply
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	54	54
Purchases	0	0
Acquisition of businesses	0	0
Usage	0	0
Write-off of fully amortized balances	(54)	0
Impairment	0	0
Other	0	0
Balance at end of period	0	54
Less accumulated amortization	0	(54)
Net carrying amount	0	0
Fuel
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	72	72
Purchases	0	0
Acquisition of businesses	0	0
Usage	0	0
Write-off of fully amortized balances	(23)	0
Impairment	0	0
Other	0	0
Balance at end of period	49	72
Less accumulated amortization	(45)	(67)
Net carrying amount	4	5
Customer
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	16	16
Purchases	0	0
Acquisition of businesses	0	0
Usage	0	0
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	0
Balance at end of period	16	16
Less accumulated amortization	(9)	(8)
Net carrying amount	7	8
Customer Relationships
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	816	834
Purchases	0	0
Acquisition of businesses	18	0
Usage	0	0
Write-off of fully amortized balances	0	0
Impairment	0	(18)
Other	0	0
Balance at end of period	834	816
Less accumulated amortization	(698)	(663)
Net carrying amount	136	153
Write-off of accumulated amortization included in impairment of finite lived assets		10
Marketing Partnerships
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	88	88
Purchases	0	0
Acquisition of businesses	0	0
Usage	0	0
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	0
Balance at end of period	88	88
Less accumulated amortization	(54)	(49)
Net carrying amount	34	39
Trade Names
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	342	342
Purchases	0	0
Acquisition of businesses	0	0
Usage	0	0
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	0
Balance at end of period	342	342
Less accumulated amortization	(182)	(159)
Net carrying amount	160	183
PPA
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	1,286	1,286
Purchases	0	0
Acquisition of businesses	0
Usage	0	0
Write-off of fully amortized balances	0	0
Impairment	(6)	0
Other	5	0
Balance at end of period	1,285	1,286
Less accumulated amortization	(205)	(143)
Net carrying amount	1,080	1,143
Other
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	198	213
Purchases	32	34
Acquisition of businesses	0	18
Usage	(28)	(44)
Write-off of fully amortized balances	0	0
Impairment	0	(23)
Other	(19)	0
Balance at end of period	183	198
Less accumulated amortization	(34)	(27)
Net carrying amount	$ 149	171
Write-off of accumulated amortization included in impairment of finite lived assets		$ 8

Goodwill and Other Intangibles - Schedule of Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	$ 207	$ 231	$ 238
Emission Allowances
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	73	66	60
Energy Supply
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	0	7	5
Fuel
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	1	2	2
Customer
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	1	2	2
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	35	49	67
Marketing Partnerships
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	5	8	14
Trade Names
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	23	22	23
PPA
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	62	64	51
Other
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	$ 7	$ 11	$ 14

Goodwill and Other Intangibles - Schedule of Estimated Amortization of Intangible Asset for the Next Five Years (Details) $ in Millions	Dec. 31, 2017 USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	$ 159
2019	150
2020	132
2021	128
2022	120
Emission Allowances
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	33
2019	30
2020	16
2021	16
2022	15
Fuel
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	1
2019	0
2020	0
2021	0
2022	0
Customer
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	1
2019	1
2020	1
2021	1
2022	1
Customer Relationships
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	25
2019	21
2020	17
2021	13
2022	7
Marketing Partnerships
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	5
2019	4
2020	4
2021	4
2022	3
Trade Names
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	22
2019	22
2020	22
2021	22
2022	22
PPA
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	64
2019	64
2020	64
2021	64
2022	64
Other
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	8
2019	8
2020	8
2021	8
2022	$ 8

Goodwill and Other Intangibles - Out of Market Contracts (Details) - Out of Market Contracts $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Out of Market Contracts Five Year Maturity
2018	$ 25
2019	25
2020	26
2021	23
2022	10
Power Contracts
Out of Market Contracts Five Year Maturity
2018	16
2019	16
2020	17
2021	14
2022	1
Lease Agreements
Out of Market Contracts Five Year Maturity
2018	9
2019	9
2020	9
2021	9
2022	$ 9

Debt and Capital Leases - Schedule of Long-term Debt and Capital Leases (Details) - USD ($) $ in Millions			12 Months Ended
	Jan. 24, 2017	Jun. 30, 2016	Dec. 31, 2017	Dec. 07, 2017	May 26, 2017	Feb. 17, 2017	Dec. 31, 2016	Aug. 18, 2016	Aug. 02, 2016	May 23, 2016
Debt Instrument
Long-term debt			$ 16,633				$ 16,704
Capital Lease Obligations			5				6
Subtotal			16,638				16,710
Less current maturities			(688)				(516)
Less debt issuance costs			(204)				(188)
Discounts			(30)				(49)
Total long-term debt and capital leases			15,716				15,957
Debt Instrument, Unamortized Discount [Abstract]
Total discounts			(30)				(49)
Term loan facility, due 2023
Debt Instrument, Unamortized Discount [Abstract]
Discounts related to current maturities			$ 1
Alta Wind I - V lease financing arrangements, due 2034 and 2035 \| Low
Debt Instrument
Interest rate, stated percentage			5.696%
Alta Wind I - V lease financing arrangements, due 2034 and 2035 \| Maximum
Debt Instrument
Interest rate, stated percentage			7.015%
Recourse Debt
Debt Instrument
Long-term debt			$ 7,182				7,795
Recourse Debt \| Senior notes, due 2018
Debt Instrument
Long-term debt			$ 0				$ 398
Interest rate, stated percentage			7.625%				7.625%
Recourse Debt \| Senior notes, due 2021
Debt Instrument
Long-term debt			$ 0				$ 207
Interest rate, stated percentage			7.875%				7.875%		7.875%
Recourse Debt \| Senior notes, due 2022
Debt Instrument
Long-term debt			$ 992				$ 992
Interest rate, stated percentage			6.25%				6.25%
Recourse Debt \| Senior notes, due 2023
Debt Instrument
Long-term debt			$ 0				$ 869
Interest rate, stated percentage			6.625%	6.625%			6.625%
Recourse Debt \| Senior notes, due 2024
Debt Instrument
Long-term debt			$ 733				$ 733
Interest rate, stated percentage			6.25%				6.25%
Recourse Debt \| Senior notes, due 2026
Debt Instrument
Long-term debt			$ 1,000				$ 1,000
Interest rate, stated percentage			7.25%							7.25%
Recourse Debt \| Senior notes, due 2027
Debt Instrument
Long-term debt			$ 1,250				1,250
Interest rate, stated percentage			6.625%						6.625%
Recourse Debt \| Senior notes, due 2028
Debt Instrument
Long-term debt			$ 870				0
Interest rate, stated percentage			5.75%	5.75%
Recourse Debt \| Term loan facility, due 2023
Debt Instrument
Long-term debt		$ 1,900	$ 1,872				1,891
Debt Instrument, Unamortized Discount [Abstract]
Unamortized discount on debt instruments			$ (7)				(9)
Recourse Debt \| Term loan facility, due 2023 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)	2.25%	2.75%	2.25%
Recourse Debt \| Tax-exempt bonds
Debt Instrument
Long-term debt			$ 465				455
Recourse Debt \| Tax-exempt bonds \| Low
Debt Instrument
Interest rate, stated percentage			4.125%
Recourse Debt \| Tax-exempt bonds \| Maximum
Debt Instrument
Interest rate, stated percentage			6.00%
Non Recourse Debt
Debt Instrument
Long-term debt			$ 9,451				8,909
Non Recourse Debt \| NRG Yield Operating LLC Senior Notes, due 2024
Debt Instrument
Long-term debt			$ 500				500
Interest rate, stated percentage			5.375%
Non Recourse Debt \| NRG Yield Operating LLC Senior Notes, due 2026
Debt Instrument
Long-term debt			$ 350				350
Interest rate, stated percentage			5.00%					5.00%
Non Recourse Debt \| NRG Yield, Inc. Convertible Senior Notes, due 2019
Debt Instrument
Long-term debt			$ 345				345
Interest rate, stated percentage			3.50%
Debt Instrument, Unamortized Discount [Abstract]
Unamortized discount on debt instruments			$ (5)				(10)
Non Recourse Debt \| NRG Yield, Inc. Convertible Senior Notes, due 2020
Debt Instrument
Long-term debt			$ 288				288
Interest rate, stated percentage			3.25%
Debt Instrument, Unamortized Discount [Abstract]
Unamortized discount on debt instruments			$ (13)				(17)
Non Recourse Debt \| NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (b)
Debt Instrument
Long-term debt			$ 55				0
Non Recourse Debt \| NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (b) \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			2.50%
Non Recourse Debt \| El Segundo Energy Center, due 2023
Debt Instrument
Long-term debt			$ 400				443
Non Recourse Debt \| El Segundo Energy Center, due 2023 \| LIBOR \| Low
Debt Instrument
Basis spread on variable rate (as a percent)			1.75%
Non Recourse Debt \| El Segundo Energy Center, due 2023 \| LIBOR \| Maximum
Debt Instrument
Basis spread on variable rate (as a percent)			2.375%
Non Recourse Debt \| Marsh Landing, due 2017 and 2023
Debt Instrument
Long-term debt			$ 318				370
Non Recourse Debt \| Marsh Landing Term Loan Due 2017 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			1.75%
Non Recourse Debt \| Marsh Landing Term Loan Due 2023 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			1.875%
Non Recourse Debt \| Alta Wind I - V lease financing arrangements, due 2034 and 2035
Debt Instrument
Long-term debt			$ 926				965
Non Recourse Debt \| Walnut Creek, term loans due 2023
Debt Instrument
Long-term debt			$ 267				310
Non Recourse Debt \| Walnut Creek, term loans due 2023 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			1.625%
Non Recourse Debt \| Utah Portfolio, due 2022
Debt Instrument
Long-term debt			$ 278				287
Non Recourse Debt \| Utah Portfolio, due 2022 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			2.625%
Non Recourse Debt \| Tapestry, due 2021
Debt Instrument
Long-term debt			$ 162				172
Non Recourse Debt \| Tapestry, due 2021 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			1.625%
Non Recourse Debt \| CVSR, due 2037
Debt Instrument
Long-term debt			$ 746				771
Non Recourse Debt \| CVSR, due 2037 \| Low
Debt Instrument
Interest rate, stated percentage			2.339%
Non Recourse Debt \| CVSR, due 2037 \| Maximum
Debt Instrument
Interest rate, stated percentage			3.775%
Non Recourse Debt \| CVSR HoldCo, due 2037
Debt Instrument
Long-term debt			$ 194				199
Interest rate, stated percentage			4.68%
Non Recourse Debt \| Alpine, due 2022
Debt Instrument
Long-term debt			$ 135				145
Non Recourse Debt \| Alpine, due 2022 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			1.75%
Non Recourse Debt \| Energy Center Minneapolis, due 2025
Debt Instrument
Long-term debt			$ 83				96
Non Recourse Debt \| Energy Center Minneapolis, due 2025 \| Low
Debt Instrument
Interest rate, stated percentage			5.95%
Non Recourse Debt \| Energy Center Minneapolis, due 2025 \| Maximum
Debt Instrument
Interest rate, stated percentage			7.25%
Non Recourse Debt \| NRG Energy Center Minneapolis LLC Senior Secured Notes, due 2025
Debt Instrument
Interest rate, stated percentage			5.95%
Non Recourse Debt \| Energy Center Minneapolis, due 2031
Debt Instrument
Long-term debt			$ 125				125
Interest rate, stated percentage			3.55%
Non Recourse Debt \| Viento, due 2023
Debt Instrument
Long-term debt			$ 163				178
Non Recourse Debt \| Viento, due 2023 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			3.00%
Non Recourse Debt \| NRG Yield - other
Debt Instrument
Long-term debt			$ 579				603
Non Recourse Debt \| NRG Yield, Inc.
Debt Instrument
Long-term debt			5,914				6,147
Non Recourse Debt \| Ivanpah, due 2033 and 2038
Debt Instrument
Long-term debt			$ 1,073				1,113
Non Recourse Debt \| Ivanpah, due 2033 and 2038 \| Low
Debt Instrument
Interest rate, stated percentage			2.285%
Non Recourse Debt \| Ivanpah, due 2033 and 2038 \| Maximum
Debt Instrument
Interest rate, stated percentage			4.256%
Non Recourse Debt \| Carlsbad Energy Project
Debt Instrument
Long-term debt			$ 427				0
Interest rate, stated percentage					4.12%
Non Recourse Debt \| Carlsbad Energy Project \| LIBOR \| Low
Debt Instrument
Basis spread on variable rate (as a percent)			1.625%
Non Recourse Debt \| Carlsbad Energy Project \| LIBOR \| Maximum
Debt Instrument
Basis spread on variable rate (as a percent)			4.12%
Non Recourse Debt \| Agua Caliente, due 2037
Debt Instrument
Long-term debt			$ 818				849
Non Recourse Debt \| Agua Caliente, due 2037 \| Low
Debt Instrument
Interest rate, stated percentage			2.395%
Non Recourse Debt \| Agua Caliente, due 2037 \| Maximum
Debt Instrument
Interest rate, stated percentage			3.633%
Non Recourse Debt \| Agua Caliente Borrower 1, due 2038
Debt Instrument
Long-term debt			$ 89				0
Interest rate, stated percentage			5.43%			5.43%
Non Recourse Debt \| Cedro Hill, due 2029
Debt Instrument
Long-term debt			$ 151				163
Non Recourse Debt \| Cedro Hill, due 2029 \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)			1.75%
Non Recourse Debt \| Midwest Generation, due 2019
Debt Instrument
Long-term debt			$ 152				231
Interest rate, stated percentage			4.39%
Debt Instrument, Unamortized Discount [Abstract]
Unamortized discount on debt instruments			$ (5)				(13)
Non Recourse Debt \| NRG Other Renewables
Debt Instrument
Long-term debt			647				269
Non Recourse Debt \| NRG Other
Debt Instrument
Long-term debt			180				137
Non Recourse Debt \| NRG Energy
Debt Instrument
Long-term debt			$ 3,537				$ 2,762

Debt and Capital Leases - Annual Payments Based on the Maturities of Debt and Capital Leases (Details) $ in Millions	Dec. 31, 2017 USD ($)
Debt Disclosure [Abstract]
2018	$ 695
2019	933
2020	805
2021	606
2022	1,854
Thereafter	11,745
Total	$ 16,638

Debt and Capital Leases - Recourse Debt Issuances/Repurchases (Details) - USD ($) $ in Millions				12 Months Ended
	Dec. 07, 2017	Aug. 02, 2016	May 23, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument
Loss on debt extinguishment				$ 53	$ 142	$ (10)
Senior notes
Debt Instrument
Accrued interest					77
Loss on debt extinguishment					117
Deferred financing costs					$ 16
Recourse Debt \| Senior Notes due 2028
Debt Instrument
Proceeds from issuance of senior notes	$ 870
Interest rate, stated percentage	5.75%			5.75%
Recourse Debt \| Senior Notes due 2026
Debt Instrument
Proceeds from issuance of senior notes			$ 1,000
Interest rate, stated percentage			7.25%	7.25%
Recourse Debt \| Senior Notes due 2027
Debt Instrument
Proceeds from issuance of senior notes		$ 1,250
Interest rate, stated percentage		6.625%		6.625%
Recourse Debt \| Senior notes, due 2020
Debt Instrument
Interest rate, stated percentage		8.25%			8.25%
Principal Repurchased					$ 1,058
Cash Paid					$ 1,129
Average Early Redemption Percentage					103.12%
Recourse Debt \| Senior notes, due 2018
Debt Instrument
Interest rate, stated percentage				7.625%	7.625%
Principal Repurchased				$ 398	$ 641
Cash Paid				$ 411	$ 706
Average Early Redemption Percentage				101.42%	107.89%
Redemptions by cash				$ 186
Recourse Debt \| Senior notes, due 2021
Debt Instrument
Interest rate, stated percentage		7.875%		7.875%	7.875%
Principal Repurchased				$ 206	$ 922
Cash Paid				$ 218	$ 978
Average Early Redemption Percentage				102.63%	104.00%
Redemptions by cash				$ 193
Recourse Debt \| Senior notes, due 2023
Debt Instrument
Interest rate, stated percentage	6.625%			6.625%	6.625%
Principal Repurchased				$ 869	$ 67
Cash Paid				$ 915	$ 64
Average Early Redemption Percentage				103.57%	94.13%
Recourse Debt \| Senior notes, due 2022
Debt Instrument
Interest rate, stated percentage				6.25%	6.25%
Principal Repurchased					$ 108
Cash Paid					$ 105
Average Early Redemption Percentage				35.00%	94.73%
Recourse Debt \| Senior notes
Debt Instrument
Principal amount redeemed				$ 1,500
Principal Repurchased				1,473	$ 2,967
Cash Paid				$ 1,544	$ 3,145
Average Early Redemption Percentage				25.00%
Accrued interest				$ 29
Loss on debt extinguishment				49
Write off of deferred debt issuance cost				$ 7
Recourse Debt \| Senior Notes 2024
Debt Instrument
Interest rate, stated percentage				6.25%	6.25%
Principal Repurchased					$ 171
Cash Paid					$ 163
Average Early Redemption Percentage				35.00%	94.52%

Debt and Capital Leases - Senior Notes Outstanding (Details) - Recourse Debt	Dec. 31, 2017	Dec. 07, 2017	Dec. 31, 2016	Aug. 02, 2016	May 23, 2016
Senior notes, due 2022
Debt Instrument
Interest rate, stated percentage	6.25%		6.25%
Senior notes, due 2024
Debt Instrument
Interest rate, stated percentage	6.25%		6.25%
Senior notes, due 2026
Debt Instrument
Interest rate, stated percentage	7.25%				7.25%
Senior notes, due 2027
Debt Instrument
Interest rate, stated percentage	6.625%			6.625%
Senior notes, due 2028
Debt Instrument
Interest rate, stated percentage	5.75%	5.75%

Debt and Capital Leases - Recourse Debt Redemption Period (Details) - Recourse Debt	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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.
Senior Notes
Debt Instrument
Average Early Redemption Percentage	25.00%
Senior Notes, due 2022
Debt Instrument
Average Early Redemption Percentage	35.00%	94.73%
Senior Notes, due 2022 \| Treasury Rate
Debt Instrument
Treasury rate redemption (as percentage)	0.50%
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Senior Notes 2024
Debt Instrument
Average Early Redemption Percentage	35.00%	94.52%
Senior Notes 2024 \| Treasury Rate
Debt Instrument
Treasury rate redemption (as percentage)	0.50%
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Senior Notes due 2026 \| Treasury Rate
Debt Instrument
Treasury rate redemption (as percentage)	0.50%
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Senior Notes due 2028 \| Treasury Rate
Debt Instrument
Treasury rate redemption (as percentage)	0.50%
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Redemption Period Prior to January 15, 2021 \| Senior Notes due 2026
Debt Instrument
Redemption percentage	35.00%
Redemption Period Prior to January 15, 2023 \| Senior Notes due 2026
Debt Instrument
Redemption percentage	105.75%
Redemption Period Prior to January 15, 2023 \| Senior Notes due 2028
Debt Instrument
Redemption percentage	100.00%
Present value of note(as percentage)	1.02875
Redemption Period Prior To 15 July 2017 \| Senior Notes, due 2022
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 percentage	106.25%
Redemption Period Prior To 15 July 2018 \| Senior Notes, due 2022
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 percentage	100.00%
Present value of note(as percentage)	1.03125
July 15, 2018 to July 14, 2019 \| Senior Notes, due 2022
Debt Instrument
Redemption percentage	103.125%
July 15, 2019 to July 14, 2020 \| Senior Notes, due 2022
Debt Instrument
Redemption percentage	101.563%
July 15, 2020 and thereafter \| Senior Notes, due 2022
Debt Instrument
Redemption percentage	100.00%
Redemption Period Prior To 1 May 2017 \| Senior Notes 2024
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 percentage	106.25%
Redemption Period Prior To 1 May 2019 \| Senior Notes 2024
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 percentage	100.00%
Present value of note(as percentage)	1.03125
May 1, 2019 to April 30, 2020 \| Senior Notes 2024
Debt Instrument
Redemption percentage	103.125%
May 1, 2020 to April 30, 2021 \| Senior Notes 2024
Debt Instrument
Redemption percentage	102.083%
May 1, 2021 to April 30, 2022 \| Senior Notes 2024
Debt Instrument
Redemption percentage	101.042%
May 1, 2022 and thereafter \| Senior Notes 2024
Debt Instrument
Redemption percentage	100.00%
Redemption Period Prior to 15 May 2019 \| Senior Notes due 2026
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
Average Early Redemption Percentage	35.00%
Redemption percentage	107.25%
Redemption Period Prior To 15 May 2021 \| Senior Notes due 2026
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 percentage	100.00%
Present value of note(as percentage)	1.03625
May 15, 2021 to May 14, 2022 \| Senior Notes due 2026
Debt Instrument
Redemption percentage	103.625%
May 15, 2022 to May 14, 2023 \| Senior Notes due 2026
Debt Instrument
Redemption percentage	102.417%
May 15, 2023 to May 14, 2024 \| Senior Notes due 2026
Debt Instrument
Redemption percentage	101.208%
May 15, 2024 and thereafter \| Senior Notes due 2026
Debt Instrument
Redemption percentage	100.00%
Redemption Period Prior To 15 July 2019 \| Senior Notes due 2027
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 Prior To 15 July 2021 \| Senior Notes due 2027
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%.
July 15, 2021 to July14, 2022 \| Senior Notes due 2027
Debt Instrument
Redemption percentage	103.313%
July 15, 2022 to July 14, 2023 \| Senior Notes due 2027
Debt Instrument
Redemption percentage	102.208%
July 15, 2023 to July 14, 2024 \| Senior Notes due 2027
Debt Instrument
Redemption percentage	101.104%
July 15, 2024 and thereafter \| Senior Notes due 2027
Debt Instrument
Redemption percentage	100.00%
January 15, 2023 to January 14, 2024 \| Senior Notes due 2028
Debt Instrument
Redemption percentage	102.875%
January 15, 2024 to January 14, 2025 \| Senior Notes due 2028
Debt Instrument
Redemption percentage	101.917%
January 15, 2025 to January 14, 2026 \| Senior Notes due 2028
Debt Instrument
Redemption percentage	100.958%
January 15, 2026 and thereafter \| Senior Notes due 2028
Debt Instrument
Redemption percentage	100.00%

Debt and Capital Leases - Recourse Debt, Senior Credit Facility, Tax Exempt Bonds (Details) $ in Millions			12 Months Ended
	Jan. 24, 2017	Jun. 30, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Debt Instrument
Long-term debt			$ 16,633	$ 16,704
Net (loss)/gain on debt extinguishment			(53)	(142)	$ 10
Senior Credit Facility
Debt Instrument
Securitization threshold		66.00%
Recourse Debt
Debt Instrument
Long-term debt			7,182	7,795
Recourse Debt \| Term loan facility, due 2023
Debt Instrument
Long-term debt		$ 1,900	1,872	1,891
Percent of face value		99.50%
Periodic payment, percentage of principal		0.0025
Net (loss)/gain on debt extinguishment		$ (21)
Recourse Debt \| Indian River Power tax exempt bonds, due 2040
Debt Instrument
Long-term debt			$ 57	57
Interest rate, stated percentage			6.00%
Recourse Debt \| Indian River Power LLC, tax exempt bonds, due 2045
Debt Instrument
Long-term debt			$ 190	190
Interest rate, stated percentage			5.375%
Recourse Debt \| Dunkirk Power LLC, tax exempt bonds, due 2042
Debt Instrument
Long-term debt			$ 59	59
Interest rate, stated percentage			5.875%
Recourse Debt \| City of Texas City, tax exempt bonds, due 2045
Debt Instrument
Long-term debt			$ 32	22
Interest rate, stated percentage			4.125%
Recourse Debt \| Fort Bend County, tax exempt bonds, due 2038
Debt Instrument
Long-term debt			$ 54	54
Interest rate, stated percentage			4.75%
Recourse Debt \| Fort Bend County, tax exempt bonds, due 2042
Debt Instrument
Long-term debt			$ 73	73
Interest rate, stated percentage			4.75%
Recourse Debt \| Tax-exempt bonds
Debt Instrument
Long-term debt			$ 465	$ 455
Recourse Debt \| LIBOR \| Term loan facility, due 2023
Debt Instrument
Basis spread on variable rate (as a percent)	2.25%	2.75%	2.25%
Recourse Debt \| LIBOR floor \| Term loan facility, due 2023
Debt Instrument
Basis spread on variable rate (as a percent)		0.75%
Revolving Credit Facility \| 2016 Tranche A Revolving Credit Facility due 2018
Debt Instrument
Revolving credit facility		$ 289
Revolving Credit Facility \| 2016 Tranche B Revolving Credit Facility due 2021
Debt Instrument
Basis spread on variable rate (as a percent)		2.25%
Revolving credit facility		$ 2,200

Debt and Capital Leases - Non-Recourse Debt, Yield Notes and Project Financing (Details) - USD ($)				3 Months Ended	12 Months Ended
	May 26, 2017	Feb. 17, 2017	Aug. 18, 2016	Dec. 31, 2016	Dec. 31, 2017
Debt Instrument
Long-term debt				$ 16,704,000,000	$ 16,633,000,000
Sun Edison Utility-Scale Solar and Wind \| In-development Wind Assets
Debt Instrument
Non-recourse project level debt				222,000,000	222,000,000
Non Recourse Debt
Debt Instrument
Long-term debt				8,909,000,000	9,451,000,000
Revolving Credit Facility \| Carlsbad Financing Agreement
Debt Instrument
Construction loan	$ 194,000,000				20,000,000
Revolving Credit Facility \| Letter of Credit
Debt Instrument
Letters of credit outstanding					29,000,000
Working capital loan facility	83,000,000
Revolving Credit Facility \| Working Capital Facility
Debt Instrument
Working capital loan facility	4,000,000
NRG Yield Revolving Credit Facility
Debt Instrument
Amount outstanding under revolver					55,000,000
NRG Yield Revolving Credit Facility \| Letter of Credit
Debt Instrument
Letters of credit outstanding					$ 74,000,000
NRG Yield Operating LLC Senior Notes, due 2026 \| Non Recourse Debt
Debt Instrument
Proceeds from issuance of senior notes			$ 350,000,000
Interest rate, stated percentage			5.00%		5.00%
Long-term debt				350,000,000	$ 350,000,000
Agua Caliente Borrower 1, due 2038 \| Non Recourse Debt
Debt Instrument
Interest rate, stated percentage		5.43%			5.43%
Senior notes issued		$ 130,000,000
Long-term debt				0	$ 89,000,000
Carlsbad Energy Project \| Non Recourse Debt
Debt Instrument
Proceeds from issuance of senior notes	$ 407,000,000
Interest rate, stated percentage	4.12%
Long-term debt				0	427,000,000
Carlsbad Energy Project \| Notes Payable to Banks
Debt Instrument
Long-term debt					407,000,000
Utah Portfolio \| Non Recourse Debt
Debt Instrument
Long-term debt				287,000,000	278,000,000
Additional debt borrowed				65,000,000	$ 65,000,000
Utah Portfolio \| Non Recourse Debt \| LIBOR
Debt Instrument
Basis spread on variable rate (as a percent)					2.625%
NRG Energy Center Minneapolis Series D Notes \| Non Recourse Debt
Debt Instrument
Interest rate, stated percentage					3.55%
Senior notes issued				$ 125,000,000
NRG Energy Center Minneapolis Series D Notes \| Shelf Facility
Debt Instrument
Long-term debt					$ 70,000,000

Debt and Capital Leases - Alta Wind Lease Financings Arrangements (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument
Long-term debt	$ 16,633	$ 16,704
Total \| Low
Debt Instrument
Interest rate, stated percentage	5.696%
Total \| Maximum
Debt Instrument
Interest rate, stated percentage	7.015%
Alta Wind Holdings \| Alta Wind I \| Leasing Arrangement
Debt Instrument
Long-term debt	$ 231
Interest rate, stated percentage	7.015%
Alta Wind Holdings \| Alta Wind I \| Letter of Credit
Debt Instrument
Long-term debt	$ 16
Alta Wind Holdings \| Alta Wind I \| Letter of Credit \| Low
Debt Instrument
Interest rate, stated percentage	3.00%
Alta Wind Holdings \| Alta Wind I \| Letter of Credit \| Maximum
Debt Instrument
Interest rate, stated percentage	3.25%
Alta Wind Holdings \| Alta Wind II \| Leasing Arrangement
Debt Instrument
Long-term debt	$ 183
Interest rate, stated percentage	5.696%
Alta Wind Holdings \| Alta Wind II \| Letter of Credit
Debt Instrument
Long-term debt	$ 27
Interest rate, stated percentage	1.25%
Alta Wind Holdings \| Alta Wind III \| Leasing Arrangement
Debt Instrument
Long-term debt	$ 191
Interest rate, stated percentage	6.067%
Alta Wind Holdings \| Alta Wind III \| Letter of Credit
Debt Instrument
Long-term debt	$ 27
Interest rate, stated percentage	1.75%
Alta Wind Holdings \| Alta Wind IV \| Leasing Arrangement
Debt Instrument
Long-term debt	$ 123
Interest rate, stated percentage	5.938%
Alta Wind Holdings \| Alta Wind IV \| Letter of Credit
Debt Instrument
Long-term debt	$ 19
Interest rate, stated percentage	1.75%
Alta Wind Holdings \| Alta Wind V \| Leasing Arrangement
Debt Instrument
Long-term debt	$ 198
Interest rate, stated percentage	6.071%
Alta Wind Holdings \| Alta Wind V \| Letter of Credit
Debt Instrument
Long-term debt	$ 30
Interest rate, stated percentage	1.75%
Alta Wind Holdings \| Total \| Leasing Arrangement
Debt Instrument
Long-term debt	$ 926
Alta Wind Holdings \| Total \| Letter of Credit
Debt Instrument
Long-term debt	$ 119

Debt and Capital Leases - Midwest, CVSR and Capistrano Financing (Details) - USD ($) $ in Millions	Jul. 15, 2016	Jul. 13, 2016	Apr. 07, 2016	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument
Long-term debt				$ 16,633	$ 16,704
Cedro Hill, Broken Bow, & Crofton Bluffs
Debt Instrument
Credit facility increased borrowing capacity		$ 312
Proceeds from lines of credit		$ 87
Non Recourse Debt
Debt Instrument
Long-term debt				$ 9,451	8,909
Non Recourse Debt \| Midwest Generation, due 2019
Debt Instrument
Interest rate, stated percentage				4.39%
Long-term debt				$ 152	$ 231
Non Recourse Debt \| CVSR Financing Agreement
Debt Instrument
Interest rate, stated percentage	4.68%
Senior notes issued	$ 200
Net proceeds from notes	$ 199
Midwest Generation \| Non Recourse Debt
Debt Instrument
Proceeds from sale of unforced capacity			$ 253
Interest rate, stated percentage			4.39%

Debt and Capital Leases - Interest Rate Swaps Project Financing (Details) $ in Millions	Dec. 31, 2017 USD ($)
Interest Rate Swap
Debt Instrument
Derivative, notional amount (in usd)	$ 3,876
NRG Other
Debt Instrument
% of Principal	75.00%
NRG Other \| Interest Rate Swap
Debt Instrument
Derivative, notional amount (in usd)	$ 653
NRG Energy \| Recourse Debt
Debt Instrument
% of Principal	85.00%
NRG Energy \| Recourse Debt \| Interest Rate Swap
Debt Instrument
Derivative, notional amount (in usd)	$ 1,000
El Segundo Energy Center \| Non Recourse Debt
Debt Instrument
% of Principal	75.00%
El Segundo Energy Center \| Non Recourse Debt \| Interest Rate Swap
Debt Instrument
Derivative, notional amount (in usd)	$ 340
South Trent Wind LLC \| Non Recourse Debt
Debt Instrument
% of Principal	75.00%
NRG Solar Roadrunner LLC \| Non Recourse Debt
Debt Instrument
% of Principal	75.00%
NRG Solar Roadrunner LLC \| Non Recourse Debt \| Interest Rate Swap
Debt Instrument
Fixed Interest Rate	4.313%
Derivative, notional amount (in usd)	$ 26
NRG Solar Alpine LLC \| Non Recourse Debt
Debt Instrument
% of Principal	85.00%
NRG Solar Alpine LLC \| Non Recourse Debt \| Interest Rate Swap
Debt Instrument
Derivative, notional amount (in usd)	$ 115
NRG Solar Avra Valley LLC \| Non Recourse Debt
Debt Instrument
% of Principal	85.00%
NRG Solar Avra Valley LLC \| Non Recourse Debt \| Interest Rate Swap
Debt Instrument
Fixed Interest Rate	2.333%
Derivative, notional amount (in usd)	$ 46
NRG Marsh Landing
Debt Instrument
% of Principal	75.00%
NRG Marsh Landing \| Interest Rate Swap
Debt Instrument
Fixed Interest Rate	3.244%
Derivative, notional amount (in usd)	$ 295
Utah Portfolio
Debt Instrument
% of Principal	80.00%
Utah Portfolio \| Interest Rate Swap
Debt Instrument
Derivative, notional amount (in usd)	$ 223
DGPV 4
Debt Instrument
% of Principal	85.00%
DGPV 4 \| Interest Rate Swap
Debt Instrument
Derivative, notional amount (in usd)	$ 95
EME Project Financings \| Non Recourse Debt \| Broken Bow \| Interest Rate Swap
Debt Instrument
% of Principal	75.00%
Derivative, notional amount (in usd)	$ 55
EME Project Financings \| Non Recourse Debt \| Cedro Hill \| Interest Rate Swap
Debt Instrument
% of Principal	90.00%
Derivative, notional amount (in usd)	$ 136
EME Project Financings \| Non Recourse Debt \| Crofton Bluffs \| Interest Rate Swap
Debt Instrument
% of Principal	75.00%
Derivative, notional amount (in usd)	$ 36
EME Project Financings \| Non Recourse Debt \| Laredo Ridge \| Interest Rate Swap
Debt Instrument
% of Principal	75.00%
Fixed Interest Rate	2.31%
Derivative, notional amount (in usd)	$ 75
EME Project Financings \| Non Recourse Debt \| Tapestry \| Interest Rate Swap
Debt Instrument
% of Principal	75.00%
Fixed Interest Rate	2.21%
Derivative, notional amount (in usd)	$ 146
EME Project Financings \| Non Recourse Debt \| Tapestry \| Interest Rate Swap
Debt Instrument
% of Principal	50.00%
Fixed Interest Rate	3.57%
Derivative, notional amount (in usd)	$ 60
EME Project Financings \| Non Recourse Debt \| Viento Funding II, Inc., due in 2023 \| Interest Rate Swap
Debt Instrument
% of Principal	90.00%
Derivative, notional amount (in usd)	$ 148
EME Project Financings \| Non Recourse Debt \| Viento Funding II, Inc., due in 2028 \| Interest Rate Swap
Debt Instrument
% of Principal	90.00%
Fixed Interest Rate	4.985%
Derivative, notional amount (in usd)	$ 65
EME Project Financings \| Non Recourse Debt \| Walnut Creek Energy \| Interest Rate Swap
Debt Instrument
% of Principal	75.00%
Derivative, notional amount (in usd)	$ 239
EME Project Financings \| Non Recourse Debt \| WCEP Holdings \| Interest Rate Swap
Debt Instrument
% of Principal	90.00%
Fixed Interest Rate	4.003%
Derivative, notional amount (in usd)	$ 45
Alta Wind Holdings \| Non Recourse Debt \| AWAM \| Interest Rate Swap
Debt Instrument
% of Principal	100.00%
Fixed Interest Rate	2.47%
Derivative, notional amount (in usd)	$ 17
Maturity - June14, 2020 \| South Trent Wind LLC \| Non Recourse Debt \| Interest Rate Swap
Debt Instrument
Fixed Interest Rate	3.265%
Derivative, notional amount (in usd)	$ 40
Maturity - June 14, 2028 \| South Trent Wind LLC \| Non Recourse Debt \| Interest Rate Swap
Debt Instrument
Fixed Interest Rate	4.95%
Derivative, notional amount (in usd)	$ 21

Asset Retirement Obligations (Details) $ in Millions	12 Months Ended
Asset Retirement Obligations (Details) $ in Millions	Dec. 31, 2017 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at the beginning of the period	$ 735
Revisions in estimates for current obligations	(3)
Additions	9
Spending for current obligations	(21)
Accretion — Expense	35
Accretion — Nuclear decommissioning	16
Balance at the ending of the period	$ 771

Benefit Plans and Other Postretirement Benefits - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
GenOn
Benefit Plans and Other Postretirement Benefits
Pension liability retained	$ 92		$ 120
Liability retained other post-employment and retiree health and welfare benefits	25
Restructuring Support Agreement
Benefit Plans and Other Postretirement Benefits
Amount of pension liability future contributions	13	$ 13
Restructuring Support Agreement \| GenOn
Benefit Plans and Other Postretirement Benefits
Amount of pension liability future contributions		$ 13
Pension Benefits \| Scenario, Plan
Benefit Plans and Other Postretirement Benefits
Expects to contribute to the pension plans	31
Pension Benefits \| GenOn
Benefit Plans and Other Postretirement Benefits
Liability retained other post-employment and retiree health and welfare benefits	0		$ 0
Pension Benefits \| GenOn \| Scenario, Plan
Benefit Plans and Other Postretirement Benefits
Expects to contribute to the pension plans	$ 13

Benefit Plans and Other Postretirement Benefits - Net Benefit Costs and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016
Annual periodic pension cost
Curtailment gain	$ 0	$ 0	$ (21)
GenOn
Fair value of plan assets for pension and other post retirement benefit
Add: Retained obligation in bankruptcy proceeding				$ (25)
Pension liability retained				92	$ 120
Pension Benefits
Annual periodic pension cost
Service cost benefits earned	26	30	32
Interest cost on benefit obligation	43	43	53
Expected return on plan assets	(58)	(60)	(62)
Amortization of unrecognized net loss	4	2	2
Net periodic benefit cost	15	15	25
Pension and other post retirement benefit obligations
Benefit obligation at January 1	1,241	1,196
Service cost	26	30	32
Interest cost	43	43	53
Plan amendments	0	0
Actuarial loss/(gain)	77	40
Employee and retiree contributions	0	0
Benefit payments	(58)	(68)
Benefit obligation at December 31	1,329	1,241	1,196
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1	953	916
Actual return on plan assets	173	72
Employee and retiree contributions	0	0
Employer contributions	36	33
Benefit payments	(58)	(68)
Fair value of plan assets at December 31	1,104	953	916
Funded status at December 31 — excess of obligation over assets				(225)	(288)
Less: GenOn postretirement obligation	1,241	1,196	1,196	1,329	1,241
Pension Benefits \| GenOn
Pension and other post retirement benefit obligations
Benefit obligation at January 1	0
Benefit obligation at December 31	0	0
Fair value of plan assets for pension and other post retirement benefit
Less: GenOn postretirement obligation	0	0		0	0
Add: Retained obligation in bankruptcy proceeding				0	0
Pension Benefits \| NRG
Fair value of plan assets for pension and other post retirement benefit
Funded status at December 31 — excess of obligation over assets				(225)	(288)
Other Postretirement Benefit
Annual periodic pension cost
Service cost benefits earned	1	2	3
Interest cost on benefit obligation	4	6	9
Amortization of unrecognized prior service credit	(9)	(5)	(5)
Amortization of unrecognized net loss	(1)	0	1
Curtailment gain	0	0	(14)
Net periodic benefit cost	(5)	3	(6)
Pension and other post retirement benefit obligations
Benefit obligation at January 1	128	178
Service cost	1	2	3
Interest cost	4	6	9
Plan amendments	(1)	(42)
Actuarial loss/(gain)	6	(2)
Employee and retiree contributions	3	3
Benefit payments	(13)	(17)
Benefit obligation at December 31	128	128	178
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	3
Employer contributions	10	14
Benefit payments	(13)	(17)
Fair value of plan assets at December 31	0	0	0
Funded status at December 31 — excess of obligation over assets				(128)	(128)
Less: GenOn postretirement obligation	128	178	$ 178	128	128
Other Postretirement Benefit \| GenOn
Pension and other post retirement benefit obligations
Benefit obligation at January 1	46
Benefit obligation at December 31	38	46
Fair value of plan assets for pension and other post retirement benefit
Less: GenOn postretirement obligation	$ 46	$ 46		38	46
Add: Retained obligation in bankruptcy proceeding				(25)	(25)
Pension liability retained				13	21
Other Postretirement Benefit \| NRG
Fair value of plan assets for pension and other post retirement benefit
Funded status at December 31 — excess of obligation over assets				$ (115)	$ (107)

Benefit Plans and Other Postretirement Benefits - Amounts Recognized in the Balance Sheets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Amounts recognized in balance sheet
Current liabilities	$ 0	$ 0
Non-current liabilities	225	288
Amounts recognized in accumulated OCI
Net loss/(gain)	(53)	(94)
Prior service cost/(credit)	3	3
Total accumulated OCI	56	97
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial (gain)/loss	(37)	28
Amortization of net actuarial (gain)/loss	(4)	(2)	$ (2)
Prior service credit	0	0
Amortization of prior service cost	0	0
Total recognized in other comprehensive loss	(41)	26
Net recognized in net periodic pension (credit)/cost and OCI	(11)	24
Estimated unrecognized loss for NRG's pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year (less than)	1
Significant components of NRG's domestic pension plan
Projected benefit obligation	1,329	1,241	1,196
Accumulated benefit obligation	1,255	1,174
Fair value of plan assets	1,104	953	916
Other Postretirement Benefit
Amounts recognized in balance sheet
Current liabilities	7	8
Non-current liabilities	121	120
Amounts recognized in accumulated OCI
Net loss/(gain)	4	11
Prior service cost/(credit)	(37)	(45)
Total accumulated OCI	(41)	(56)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial (gain)/loss	6	(2)
Amortization of net actuarial (gain)/loss	1	0	(1)
Prior service credit	(1)	(41)
Amortization of prior service cost	9	5
Total recognized in other comprehensive loss	15	(38)
Net recognized in net periodic pension (credit)/cost and OCI	13	39
Expected unrecognized gain that will be amortized from accumulated OCI to net periodic cost over the next fiscal year	1
Expected amortization of unrecognized prior service credit over the next fiscal Year		7
Significant components of NRG's domestic pension plan
Projected benefit obligation	128	128	178
Fair value of plan assets	0	0	$ 0
GenOn
Amounts recognized in balance sheet
Pension benefit obligations	92	120
Liability retained other post-employment and retiree health and welfare benefits	25
Amounts recognized in accumulated OCI
Net loss/(gain)	28
GenOn \| Pension Benefits
Amounts recognized in balance sheet
Current liabilities	0	0
Non-current liabilities	0	0
Liability retained other post-employment and retiree health and welfare benefits	0	0
Significant components of NRG's domestic pension plan
Projected benefit obligation	0	0
GenOn \| Other Postretirement Benefit
Amounts recognized in balance sheet
Current liabilities	3	5
Non-current liabilities	10	16
Pension benefit obligations	13	21
Liability retained other post-employment and retiree health and welfare benefits	25	25
Significant components of NRG's domestic pension plan
Projected benefit obligation	38	46
NRG \| Pension Benefits
Amounts recognized in balance sheet
Current liabilities	0	0
Non-current liabilities	225	288
NRG \| Other Postretirement Benefit
Amounts recognized in balance sheet
Current liabilities	4	3
Non-current liabilities	111	104
Discontinued Operations \| Pension Benefits
Amounts recognized in accumulated OCI
Total accumulated OCI	(22)	(37)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Total recognized in other comprehensive loss	15	(17)
Net recognized in net periodic pension (credit)/cost and OCI	15	(17)
Discontinued Operations \| Other Postretirement Benefit
Amounts recognized in accumulated OCI
Total accumulated OCI	10	8
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Total recognized in other comprehensive loss	2	3
Net recognized in net periodic pension (credit)/cost and OCI	3	3
Continuing Operations \| Pension Benefits
Amounts recognized in accumulated OCI
Total accumulated OCI	34	60
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Total recognized in other comprehensive loss	(26)	9
Continuing Operations \| Other Postretirement Benefit
Amounts recognized in accumulated OCI
Total accumulated OCI	(31)	(48)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Total recognized in other comprehensive loss	$ 17	$ (35)

Benefit Plans and Other Postretirement Benefits - Fair Values of Pension Assets By Asset Category and Level Within the Fair Value Hierarchy (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Low
Significant assumptions used to calculate NRG's benefit expense
Aon Hewitt above median yield curve discount rate (in years)	6 months
Maximum
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
Fair value of plan assets	$ 1,104	$ 953	$ 916
Significant assumptions used to calculate NRG's benefit obligations
Discount rate	3.71%	4.26%
Rate of compensation increase	3.00%	3.00%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	4.26%	4.52%	4.16%
Expected return on plan assets	6.85%	6.65%	6.36%
Rate of compensation increase	3.00%	3.00%	3.45%
Other Postretirement Benefit
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	$ 0	$ 0	$ 0
Significant assumptions used to calculate NRG's benefit obligations
Discount rate	3.71%	4.29%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	4.29%	4.55%	4.20%
Expected return on plan assets	0.00%	0.00%	0.00%
Rate of compensation increase	0.00%	0.00%	0.00%
Common/collective trust investment — U.S. equity \| Pension Benefits
Target allocations
Target allocation of pension plan assets (as percent)	22.00%
Common/collective trust investment — non-U.S. equity \| Pension Benefits
Target allocations
Target allocation of pension plan assets (as percent)	14.00%
Common/collective trust investment — non-core assets \| Pension Benefits
Target allocations
Target allocation of pension plan assets (as percent)	19.00%
Common/collective trust investment — fixed income \| Pension Benefits
Target allocations
Target allocation of pension plan assets (as percent)	45.00%
Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets
Significant Observable Inputs (Level 2) \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets
Postretirement Benefit Obligation \| Other Postretirement Benefit
Significant assumptions used to calculate NRG's benefit expense
Year Health care cost trend rate reaches ultimate trend rate	2025		2025
Postretirement Benefit Obligation \| Before age 65 \| Other Postretirement Benefit
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	8.20%	7.00%
Postretirement Benefit Obligation \| Age 65 and after \| Other Postretirement Benefit
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	4.50%	5.00%
Net Period Benefit Cost/Credit \| Other Postretirement Benefit
Significant assumptions used to calculate NRG's benefit expense
Year Health care cost trend rate reaches ultimate trend rate	2025	2025	2023
Net Period Benefit Cost/Credit \| Before age 65 \| Other Postretirement Benefit
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	7.00%	7.25%	8.60%
Net Period Benefit Cost/Credit \| Age 65 and after \| Other Postretirement Benefit
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	5.00%	5.00%	5.00%
Other than measured at net asset value practical expedient \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	$ 735	$ 651
Other than measured at net asset value practical expedient \| Common/collective trust investment — U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	256	283
Other than measured at net asset value practical expedient \| Common/collective trust investment — non-U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	66	71
Other than measured at net asset value practical expedient \| Common/collective trust investment — non-core assets \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	178
Other than measured at net asset value practical expedient \| Common/collective trust investment — global equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets		104
Other than measured at net asset value practical expedient \| Common/collective trust investment — fixed income \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	230	190
Other than measured at net asset value practical expedient \| Short-term investment fund \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	5	3
Other than measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	5	3
Other than measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Common/collective trust investment — U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Other than measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Common/collective trust investment — non-U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Other than measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Common/collective trust investment — non-core assets \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0
Other than measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Common/collective trust investment — global equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets		0
Other than measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Common/collective trust investment — fixed income \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Other than measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Short-term investment fund \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	5	3
Other than measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	730	648
Other than measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Common/collective trust investment — U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	256	283
Other than measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Common/collective trust investment — non-U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	66	71
Other than measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Common/collective trust investment — non-core assets \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	178
Other than measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Common/collective trust investment — global equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets		104
Other than measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Common/collective trust investment — fixed income \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	230	190
Other than measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Short-term investment fund \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Measured at net asset value practical expedient \| Common/collective trust investment — non-U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	94	78
Measured at net asset value practical expedient \| Common/collective trust investment — fixed income \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	233	193
Measured at net asset value practical expedient \| Partnerships/joint ventures \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	42	31
Measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Common/collective trust investment — non-U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets
Measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Common/collective trust investment — fixed income \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets
Measured at net asset value practical expedient \| Quoted Prices in Active Markets for Identical Assets (Level 1) \| Partnerships/joint ventures \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets
Measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Common/collective trust investment — non-U.S. equity \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets
Measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Common/collective trust investment — fixed income \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets
Measured at net asset value practical expedient \| Significant Observable Inputs (Level 2) \| Partnerships/joint ventures \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets

Benefit Plans and Other Postretirement Benefits - Expected Future Benefit Payments For the Next Five Years and Other (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 56	$ 55	$ 53
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	$ 8	7
Expected reimbursement of contribution to retirement plan obligations to STPNOC in 2014	6
Pension Benefit Payments
NRG's expected future benefit payments
2018	68
2019	71
2020	75
2021	79
2022	82
2023-2027	421
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(225)	(288)
Net periodic benefit costs	15	15	25
Total recognized in other comprehensive loss	41	(26)
Pension Benefit Payments \| South Texas Project
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(76)	(74)
Net periodic benefit costs	8	7
Total recognized in other comprehensive loss	(6)	11
Other Postretirement Benefit
NRG's expected future benefit payments
2018	7
2019	8
2020	8
2021	8
2022	8
2023-2027	33
Medicare prescription drug reimbursements
2018	0
2021	0
2020	0
2021	0
2022	0
2023-2027	1
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(128)	(128)
Net periodic benefit costs	(5)	3	$ (6)
Total recognized in other comprehensive loss	(15)	38
Other Postretirement Benefit \| South Texas Project
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(24)	(23)
Net periodic benefit costs	(3)	(2)
Total recognized in other comprehensive loss	$ 5	$ (1)

Capital Structure - Changes in Common Shares issued and Outstanding (Details) - shares	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capital Structure
Preferred stock, shares authorized (in shares)	10,000,000	10,000,000	10,000,000	10,000,000
Common stock, shares authorized (in shares)	500,000,000	500,000,000	500,000,000	500,000,000
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued (in shares)		417,583,825
Beginning balance, treasury shares(in shares)		(102,140,814)
Beginning balance, common shares outstanding (in shares)		315,443,011
Ending balance, common shares issued (in shares)		418,323,134	417,583,825
Ending balance, treasury shares (in shares)		(101,580,045)	(102,140,814)
Ending balance, common shares outstanding (in shares)		316,743,089	315,443,011
Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued (in shares)		417,583,825	416,939,950	415,506,176
Beginning balance, common shares outstanding (in shares)		315,443,011	314,190,042	336,662,624
Shares issued under ESPP		560,769	609,094	283,139
Shares issued from LTIP		739,309	643,875	1,433,774
Share repurchases				(24,189,495)
Ending balance, common shares issued (in shares)	415,506,176	418,323,134	417,583,825	416,939,950
Ending balance, common shares outstanding (in shares)	336,662,624	316,743,089	315,443,011	314,190,042
Treasury Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, treasury shares(in shares)		(102,140,814)	(102,749,908)	(78,843,552)
Shares issued under ESPP		560,769	609,094	283,139
Shares issued from LTIP		0	0	0
Share repurchases				(24,189,495)
Ending balance, treasury shares (in shares)	(78,843,552)	(101,580,045)	(102,140,814)	(102,749,908)

Capital Structure - Common Stock (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

12 Months Ended

15 Months Ended

Feb. 15, 2018

Feb. 01, 2018

Jan. 19, 2018

Jan. 01, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

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

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Employee Stock Purchase Plan and 2013 Capital Allocation Plan

Dividends paid per share (in usd per share)

$ 0.030

$ 0.145

Common stock dividends, proposed annual percentage decrease

79.00%

Dividends Per Common Share (in usd per share)

$ 0.12

$ 0.24

0.58

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)

3,107,050

Commissions per share (in usd per share)

$ 0.015

Scenario, Plan

Employee Stock Purchase Plan and 2013 Capital Allocation Plan

Common stock, dividends, proposed annual amount, per share

$ 0.0012

$ 0.58

Subsequent Event

Employee Stock Purchase Plan and 2013 Capital Allocation Plan

Dividends Payable, Date Declared

Jan. 19, 2018

Dividends Per Common Share (in usd per share)

$ 0.00030

Dividends payable, date to be paid

Feb. 15, 2018

Dividends payable, date of record

Feb. 01, 2018

Common stock issued to employee from treasury stock (in shares)

175,862

Subsequent Event | Scenario, Plan

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

19,597,433

Capital Allocation Plan

Employee Stock Purchase Plan and 2013 Capital Allocation Plan

Stock repurchase program, authorized amount

$ 481

Total number of shares purchased (in shares)

5,558,920

11,104,184

4,379,907

3,146,484

1,624,360

25,813,855

Average price paid per share (in usd per share)

^[1]

$ 15.03

$ 15.06

$ 24.53

$ 25.15

$ 26.95

Amounts paid for shares purchased

$ 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 Stock (Details) - USD ($) $ in Millions			12 Months Ended
	Jun. 13, 2016	May 24, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Capital Structure
Redemption of shares (as percentage)	100.00%	100.00%
Preferred shares repurchased		$ 344.5
Repurchase of outstanding shares			$ 0.0	$ 226.0	$ 0.0
Gain on redemption of preferred shares			0.0	78.0	0.0
Carrying value of preferred stock at time of redemption			$ 0.0	$ 0.0	$ 302.0	$ 291.0
Convertible Preferred Stock
Capital Structure
Preferred stock, dividend rate (as percent)		2.822%	2.822%	2.822%	2.822%
Repurchase of outstanding shares	$ 226.0
Gain on redemption of preferred shares	78.0
Carrying value of preferred stock at time of redemption	$ 304.0

Capital Structure - Changes in Redeemable Preferred Stock (Details) - USD ($) $ in Millions			12 Months Ended
	Jun. 13, 2016	May 24, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Temporary Equity [Roll Forward]
Balance at beginning of period			$ 0	$ 302	$ 291
Accretion to redemption value				2	11
Repurchase of 2.822% redeemable preferred stock			0	(226)	0
Gain on redemption of 2.822% redeemable preferred stock			0	78	0
Balance at end of period			$ 0	$ 0	$ 302
Convertible Preferred Stock
Class of Stock [Line Items]
Preferred stock, dividend rate (as percent)		2.822%	2.822%	2.822%	2.822%
Increase (Decrease) in Temporary Equity [Roll Forward]
Repurchase of 2.822% redeemable preferred stock	$ (226)
Gain on redemption of 2.822% redeemable preferred stock	78
Balance at end of period	$ 304

Investments Accounted for by the Equity Method and Variable Interest Entities - Summary of Equity Method Investments (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Investments Accounted for by the Equity Method
Equity investments in affiliates	$ 1,038	$ 1,120
Undistributed earnings by equity investment	$ 120	$ 101
GenConn
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	50.00%
Equity investments in affiliates	$ 102
Gladstone Power Station
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	37.50%
Equity investments in affiliates	$ 139
United States \| Avenal Solar Holdings LLC
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	50.00%
Equity investments in affiliates	$ (6)
United States \| Desert Sunlight
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	25.00%
Equity investments in affiliates	$ 272
United States \| Elkhorn Ridge Wind, LLC
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	47.00%
Equity investments in affiliates	$ 73
United States \| GenConn
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	50.00%
Equity investments in affiliates	$ 102
United States \| Four Brothers Holdings
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	50.00%
Equity investments in affiliates	$ 213
United States \| Granite Mountain Renewables
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	50.00%
Equity investments in affiliates	$ 78
United States \| Iron Springs Renewables
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	50.00%
Equity investments in affiliates	$ 54
United States \| Midway-Sunset Cogeneration Company
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	50.00%
Equity investments in affiliates	$ 16
United States \| San Juan Mesa Wind Project, LLC
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	75.00%
Equity investments in affiliates	$ 66
United States \| Watson Cogeneration Company
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	49.00%
Equity investments in affiliates	$ 21
United States \| Various
Investments Accounted for by the Equity Method
Equity investments in affiliates	$ 10
Australia \| Gladstone Power Station
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	37.50%
Equity investments in affiliates	$ 139
Mechanically-complete Solar Assets \| Sun Edison Utility-Scale Solar and Wind
Investments Accounted for by the Equity Method
Equity investments in affiliates	$ 345

Investments Accounted for by the Equity Method and Variable Interest Entities - Variable Interest Entities (Details) $ in Millions	1 Months Ended
	Apr. 30, 2009	Dec. 31, 2017 USD ($) MW facility	Dec. 31, 2016 USD ($)	Nov. 02, 2016 MW	Sep. 17, 2013 USD ($)
Schedule of Equity Method Investments [Line Items]
Generation capacity (in MW) \| MW		30,000
Equity investments in affiliates		$ 1,038	$ 1,120
Long-term debt		16,633	16,704
Amount drawn on working capital facility		14
Non Recourse Debt
Schedule of Equity Method Investments [Line Items]
Long-term debt		9,451	$ 8,909
GenConn
Schedule of Equity Method Investments [Line Items]
Equity investments in affiliates		$ 102
Ownership percentage		50.00%
Number of peaking generation facilities \| facility		2
Generation capacity of peaking facility (in MW) \| MW		190
GenConn \| GenConn Working Capital Facility
Schedule of Equity Method Investments [Line Items]
Term of revolving working capital facility	5 years
GenConn \| Non Recourse Debt \| GenConn Facility
Schedule of Equity Method Investments [Line Items]
Long-term debt		$ 204			$ 237
Interest rate, stated percentage					4.73%
GenConn \| Non Recourse Debt \| GenConn Working Capital Facility
Schedule of Equity Method Investments [Line Items]
Long-term debt					$ 35
Interest rate, stated percentage					1.875%
Mechanically-complete Solar Assets \| Sun Edison Utility-Scale Solar and Wind
Schedule of Equity Method Investments [Line Items]
Generation capacity (in MW) \| MW				530
Equity investments in affiliates		$ 345

Investments Accounted for by the Equity Method and Variable Interest Entities - Other Equity Investments (Details) $ in Millions	Dec. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)
Schedule of Equity Method Investments [Line Items]
Generation capacity (in MW) \| MW	30,000
Equity investments in affiliates	$ 1,038	$ 1,120
Deficit Restoration Obligation	110
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	118	87
Net property, plant and equipment	2,337	1,534
Other long-term assets	658	954
Total assets	3,113	2,575
Current liabilities	96	59
Long-term debt	661	442
Other long-term liabilities	209	183
Total liabilities	966	684
Redeemable noncontrolling interests	78	46
Noncontrolling interests	507	529
Net assets less noncontrolling interests	$ 1,562	$ 1,316
Gladstone Power Station
Schedule of Equity Method Investments [Line Items]
Ownership percentage	37.50%
Generation capacity (in MW) \| MW	1,613
Equity investments in affiliates	$ 139

Earnings /Loss Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			3 Months Ended								12 Months Ended
	Jun. 13, 2016	May 24, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Redemption of shares (as percentage)	100.00%	100.00%
Basic and diluted loss per share attributable to NRG common stockholders
Net loss attributable to NRG Energy, Inc.			$ (1,535)	$ 171	$ (626)	$ (163)	$ (987)	$ 402	$ (271)	$ 82	$ (2,153)	$ (774)	$ (6,382)
Dividends for preferred shares											0	5	20
Gain on redemption of preferred shares											0	(78)	0
(Loss)/Income Available for Common Stockholders			$ (1,535)	$ 171	$ (626)	$ (163)	$ (987)	$ 402	$ (193)	$ 77	$ (2,153)	$ (701)	$ (6,402)
Weighted average number of common shares outstanding (in shares)											317	316	329
Loss per weighted average common share — basic and diluted (in USD PER SHARE)											$ (6.79)	$ (2.22)	$ (19.46)
Convertible Preferred Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Preferred stock, dividend rate (as percent)		2.822%									2.822%	2.822%	2.822%
Basic and diluted loss per share attributable to NRG common stockholders
Gain on redemption of preferred shares	$ (78)

Segment Reporting (Details) $ in Millions	1 Months Ended	3 Months Ended									12 Months Ended
Segment Reporting (Details) $ in Millions	Dec. 31, 2017 USD ($) MW	Dec. 31, 2017 USD ($) MW	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2017 USD ($) MW	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting Information
Generation capacity (in MW) \| MW	30,000	30,000									30,000
Income Statement
Operating revenues		$ 2,497	$ 3,049	$ 2,701	$ 2,382	$ 2,184	$ 3,421	$ 2,248	$ 2,659		$ 10,629	$ 10,512	$ 12,328
Operating expenses											8,487	8,396	10,228
Depreciation and amortization											1,056	1,172	1,351
Impairment losses											1,709	702	4,860
Development costs											67	89	154
Total operating costs and expenses											11,319	10,359	16,593
Other income - affiliate	$ 84										87	193	193
Gain/(loss) on sale of assets											16	(80)	0
Gain on postretirement benefits curtailment											0	0	21
Operating (Loss)/Income		(1,345)	376	343	39	(658)	429	164	331		(587)	266	(4,051)
Equity in (losses)/earnings of unconsolidated affiliates											31	27	36
Impairment losses on investments										$ (56)	(79)	(268)	(56)
Other income, net											38	34	26
Loss on sale of equity method investment											0	0	(14)
Loss on debt extinguishment											(53)	(142)	10
Interest expense											(890)	(895)	(937)
Loss from Continuing Operations Before Income Taxes											(1,540)	(978)	(4,986)
Income tax expense											8	5	1,345
Net Loss from Continuing Operations		(1,667)	190	99	(170)	(891)	128	(163)	(57)		(1,548)	(983)	(6,331)
(Loss)/income from discontinued operations, net of income tax		13	(27)	(741)	(34)	(164)	265	(113)	104		(789)	92	(105)
Net Loss		(1,655)	163	(642)	(203)	(1,055)	393	(276)	47		(2,337)	(891)	(6,436)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests		(120)	(8)	(16)	(40)	(68)	(9)	(5)	(35)		(184)	(117)	(54)
Net Loss Attributable to NRG Energy, Inc.		(1,535)	171	(626)	$ (163)	(987)	$ 402	$ (271)	$ 82		(2,153)	(774)	(6,382)
Balance sheet
Equity investments in affiliates	1,038	1,038				1,120					1,038	1,120
Capital expenditures	1,127	1,127				997					1,127	997
Goodwill	539	539				662					539	662
Total Assets	23,318	23,318				30,682					23,318	30,682
Generation
Income Statement
Other income - affiliate											0
Retail
Income Statement
Other income - affiliate											0
Renewables
Income Statement
Impairment losses		15	$ 14	$ 22
Other income - affiliate											0
NRG Yield
Income Statement
Other income - affiliate											0
Corporate
Income Statement
Other income - affiliate											87
Operating Segments \| Generation
Income Statement
Operating revenues											3,773	3,833	5,179
Operating expenses											3,300	3,545	4,198
Depreciation and amortization											377	516	693
Impairment losses											1,504	430	4,655
Development costs											13	15	26
Total operating costs and expenses											5,194	4,506	9,572
Other income - affiliate												0	0
Gain/(loss) on sale of assets											20	0
Gain on postretirement benefits curtailment													21
Operating (Loss)/Income											(1,401)	(673)	(4,372)
Equity in (losses)/earnings of unconsolidated affiliates											(14)	(5)	10
Impairment losses on investments											(74)	(142)	(14)
Other income, net											22	21	18
Loss on sale of equity method investment													0
Loss on debt extinguishment											0	0	0
Interest expense											(29)	(26)	(25)
Loss from Continuing Operations Before Income Taxes											(1,496)	(825)	(4,383)
Income tax expense											2	(1)	0
Net Loss from Continuing Operations											(1,498)	(824)	(4,383)
(Loss)/income from discontinued operations, net of income tax											0	0	0
Net Loss											(1,498)	(824)	(4,383)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests											0	0	0
Net Loss Attributable to NRG Energy, Inc.											(1,498)	(824)	(4,383)
Balance sheet
Equity investments in affiliates	179	179				204					179	204
Capital expenditures	481	481				522					481	522
Goodwill	165	165				276					165	276
Total Assets	7,209	7,209				13,514					7,209	13,514
Operating Segments \| Retail
Income Statement
Operating revenues											6,380	6,335	6,913
Operating expenses											5,372	5,164	6,138
Depreciation and amortization											117	111	132
Impairment losses											7	1	36
Development costs											2	4	4
Total operating costs and expenses											5,498	5,280	6,310
Other income - affiliate												0	0
Gain/(loss) on sale of assets											0	(1)
Gain on postretirement benefits curtailment													0
Operating (Loss)/Income											882	1,054	603
Equity in (losses)/earnings of unconsolidated affiliates											0	0	0
Impairment losses on investments											0	0	0
Other income, net											1	(6)	(4)
Loss on sale of equity method investment													0
Loss on debt extinguishment											0	0	0
Interest expense											(6)	6	2
Loss from Continuing Operations Before Income Taxes											877	1,054	601
Income tax expense											(9)	1	1
Net Loss from Continuing Operations											886	1,053	600
(Loss)/income from discontinued operations, net of income tax											0	0	0
Net Loss											886	1,053	600
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests											2	(2)	0
Net Loss Attributable to NRG Energy, Inc.											884	1,055	600
Balance sheet
Equity investments in affiliates	0	0				0					0	0
Capital expenditures	82	82				12					82	12
Goodwill	374	374				374					374	374
Total Assets	2,630	2,630				2,332					2,630	2,332
Operating Segments \| Renewables
Income Statement
Operating revenues											424	406	383
Operating expenses											211	217	187
Depreciation and amortization											196	185	176
Impairment losses											154	54	13
Development costs											45	40	61
Total operating costs and expenses											606	496	437
Other income - affiliate												0	0
Gain/(loss) on sale of assets											(5)	0
Gain on postretirement benefits curtailment													0
Operating (Loss)/Income											(187)	(90)	(54)
Equity in (losses)/earnings of unconsolidated affiliates											0	(58)	(7)
Impairment losses on investments											0	(105)	0
Other income, net											0	1	3
Loss on sale of equity method investment													0
Loss on debt extinguishment											(1)	0	0
Interest expense											(98)	(98)	(79)
Loss from Continuing Operations Before Income Taxes											(286)	(350)	(137)
Income tax expense											(20)	(20)	(18)
Net Loss from Continuing Operations											(266)	(330)	(119)
(Loss)/income from discontinued operations, net of income tax											0	0	0
Net Loss											(266)	(330)	(119)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests											(103)	(13)	6
Net Loss Attributable to NRG Energy, Inc.											(163)	(317)	(125)
Balance sheet
Equity investments in affiliates	4	4				26					4	26
Capital expenditures	521	521				330					521	330
Goodwill	0	0				12					0	12
Total Assets	5,129	5,129				4,921					5,129	4,921
Operating Segments \| NRG Yield
Income Statement
Operating revenues											1,009	1,035	968
Operating expenses											348	325	338
Depreciation and amortization											334	303	303
Impairment losses											44	185	1
Development costs											0	0	0
Total operating costs and expenses											726	813	642
Other income - affiliate												0	0
Gain/(loss) on sale of assets											0	0
Gain on postretirement benefits curtailment													0
Operating (Loss)/Income											283	222	326
Equity in (losses)/earnings of unconsolidated affiliates											71	60	31
Impairment losses on investments											0	0	0
Other income, net											4	3	3
Loss on sale of equity method investment													0
Loss on debt extinguishment											(3)	0	(9)
Interest expense											(306)	(284)	(267)
Loss from Continuing Operations Before Income Taxes											49	1	84
Income tax expense											72	(1)	12
Net Loss from Continuing Operations											(23)	2	72
(Loss)/income from discontinued operations, net of income tax											0	0	0
Net Loss											(23)	2	72
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests											(87)	(54)	19
Net Loss Attributable to NRG Energy, Inc.											64	56	53
Balance sheet
Equity investments in affiliates	852	852				886					852	886
Capital expenditures	31	31				23					31	23
Goodwill	0	0				0					0	0
Total Assets	8,283	8,283				8,962					8,283	8,962
Operating Segments \| Corporate
Income Statement
Operating revenues											14	77	38
Operating expenses											220	323	502
Depreciation and amortization											32	57	47
Impairment losses											0	32	133
Development costs											7	30	63
Total operating costs and expenses											259	442	745
Other income - affiliate												193	193
Gain/(loss) on sale of assets											1	(79)
Gain on postretirement benefits curtailment													0
Operating (Loss)/Income											(157)	(251)	(514)
Equity in (losses)/earnings of unconsolidated affiliates											6	13	0
Impairment losses on investments											(5)	(21)	(42)
Other income, net											11	19	13
Loss on sale of equity method investment													(14)
Loss on debt extinguishment											(49)	(142)	19
Interest expense											(451)	(495)	(574)
Loss from Continuing Operations Before Income Taxes											(645)	(877)	(1,112)
Income tax expense											(37)	26	1,350
Net Loss from Continuing Operations											(608)	(903)	(2,462)
(Loss)/income from discontinued operations, net of income tax											(789)	92	(105)
Net Loss											(1,397)	(811)	(2,567)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests											(4)	18	(37)
Net Loss Attributable to NRG Energy, Inc.											(1,393)	(829)	(2,530)
Balance sheet
Equity investments in affiliates	3	3				4					3	4
Capital expenditures	12	12				110					12	110
Goodwill	0	0				0					0	0
Total Assets	8,919	8,919				11,891					8,919	11,891
Eliminations
Income Statement
Operating revenues											(971)	(1,174)	(1,153)
Operating expenses											(964)	(1,178)	(1,135)
Depreciation and amortization											0	0	0
Impairment losses											0	0	22
Development costs											0	0	0
Total operating costs and expenses											(964)	(1,178)	(1,113)
Other income - affiliate											0	0	0
Gain/(loss) on sale of assets											0
Gain on postretirement benefits curtailment													0
Operating (Loss)/Income											(7)	4	(40)
Equity in (losses)/earnings of unconsolidated affiliates											(32)	17	2
Impairment losses on investments											0	0	0
Other income, net											0	(4)	(7)
Loss on sale of equity method investment													0
Loss on debt extinguishment											0	0	0
Interest expense											0	2	6
Loss from Continuing Operations Before Income Taxes											(39)	19	(39)
Income tax expense											0	0	0
Net Loss from Continuing Operations											(39)	19	(39)
(Loss)/income from discontinued operations, net of income tax											0		0
Net Loss											(39)	19	(39)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests											8	(66)	(42)
Net Loss Attributable to NRG Energy, Inc.											(47)	85	3
Balance sheet
Equity investments in affiliates	0	0				0					0	0
Capital expenditures	0	0				0					0	0
Goodwill	0	0				0					0	0
Total Assets	$ (8,852)	$ (8,852)				$ (10,938)					(8,852)	(10,938)
Eliminations \| Generation
Income Statement
Operating revenues											(910)	(1,033)	(896)
Eliminations \| Retail
Income Statement
Operating revenues											(5)	(4)	(6)
Eliminations \| Renewables
Income Statement
Operating revenues											(31)	(24)	(31)
Eliminations \| NRG Yield
Income Statement
Operating revenues											0	(8)	(29)
Eliminations \| Corporate
Income Statement
Operating revenues											$ (25)	$ (105)	$ (191)
NRG Yield
Segment Reporting Information
Generation capacity (in MW) \| MW	555	555									555
Consideration paid for acquisitions											$ 245

Earnings /Loss Per Share - Summary of Outstanding Equity Instruments that are Anti-dilutive and Excluded from Computation of Loss Per Share (Details) - shares shares in Millions		12 Months Ended
	May 24, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		5	5	22
Stock Compensation Plan
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		5	5	6
Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		0	0	16
Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate (as percent)	2.822%	2.822%	2.822%	2.822%

Income Taxes - Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current
State	$ 19	$ 6	$ 9
Total — current	19	6	9
Deferred
U.S. Federal	(6)	3	1,020
State	(7)	(6)	315
Foreign	2	2	1
Total — deferred	$ (11)	$ (1)	$ 1,336
Effective income tax rate (as a percent)	(0.50%)	(0.50%)	(27.00%)
Domestic and foreign components of income from continuing operations before income tax expense
U.S.	$ (1,557)	$ (989)	$ (4,997)
Foreign	17	11	11
Income tax expense	$ 8	$ 5	1,345
U.S. federal statutory rate (as a percent)	35.00%	35.00%
Reconciliation of the U.S. federal statutory rate to NRG's effective rate from continuing operations
Loss before income taxes	$ (1,540)	$ (978)	(4,986)
Tax at 35%	(539)	(342)	(1,745)
State taxes	19	0	(215)
Foreign operations	2	10	1
Federal and state tax credits, excluding PTCs	0	0	(5)
Tax Act - corporate income tax rate change	733	0	0
Valuation allowance due to corporate income tax rate change	(660)	0	0
Valuation allowance due to corporate income tax rate change	482	398	3,023
Impact of non-taxable equity earnings	(5)	22	(10)
Book goodwill impairment	30	0	340
Net interest accrued on uncertain tax positions	0	1	(3)
Production tax credits	(20)	(26)	(33)
Recognition of uncertain tax benefits	(5)	2	(15)
Tax expense attributable to consolidated partnerships	4	(1)	12
State rate change including true-up to current period activity	18	(59)	(7)
AMT refundable credit	(64)	0	0
Other	13	0	2
Income tax expense	$ 8	$ 5	$ 1,345
Effective income tax rate (as a percent)	(0.50%)	(0.50%)	(27.00%)

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
U.S. federal statutory rate (as a percent)	35.00%	35.00%
Deferred tax liabilities:
Emissions allowances	$ 15	$ 31
Derivatives, net	15	0
Cumulative translation adjustments	0	11
Investment in projects	231	378
Discount/premium on notes	2	5
Deferred financing costs	2	2
Discontinued operations	0	6
Total deferred tax liabilities	(265)	(433)
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	141	256
Difference between book and tax basis of property	596	530
Goodwill	38	83
Differences between book and tax basis of contracts	68	60
Pension and other postretirement benefits	74	122
Equity compensation	10	11
Bad debt reserve	14	12
U.S. capital loss carryforwards	1	1
U.S. Federal net operating loss carryforwards	596	728
Foreign net operating loss carryforwards	66	63
State net operating loss carryforwards	140	106
Foreign capital loss carryforwards	1	1
Federal and state tax credit carryforwards	376	446
Federal benefit on state uncertain tax positions	7	12
Intangibles amortization (excluding goodwill)	101	115
Derivatives, net	0	106
Inventory obsolescence	12	5
Other	0	7
Discontinued operations	0	2,093
Total deferred tax assets	2,241	4,757
Valuation allowance	(1,863)	(2,032)
Discontinued operations	0	(2,087)
Total deferred tax assets, net of valuation allowance	378	638
NRG's net deferred tax position
Net deferred tax asset — noncurrent	134	225
Net deferred tax liability — noncurrent	(21)	(20)
Net deferred tax asset	$ 113	$ 205

Income Taxes - Deferred Tax Assets and Valuation Allowance, Taxes Receivable and Payable (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Taxes receivable and payable
Net deferred tax assets	$ 1,900	$ 2,200
Tax Cut and Jobs Act of 2017, deferred tax asset valuation allowance adjustment, change in effective tax rate	1,800
Valuation allowance	1,863	2,032
Net deferred tax assets	113	205
Foreign net operating loss carryforwards	66	63
Foreign capital loss carryforwards	1	$ 1
Current taxes payable	7
Current taxes receivable	1
Domestic Tax Authority
Taxes receivable and payable
Operating loss carryforwards	596
State and Local Jurisdiction
Taxes receivable and payable
Valuation allowance	267
Operating loss carryforwards	140
Foreign Tax Authority
Taxes receivable and payable
Operating loss carryforwards	66
Federal Tax Authority
Taxes receivable and payable
Valuation allowance	$ 1,500

Income Taxes - Reconciliation of Uncertain Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Uncertain tax benefits
Liability for uncertainty in income taxes, noncurrent	$ 33	$ 37
Unrecognized tax benefits, income tax penalties expense	1
Accrued interest and penalties related to unrecognized tax benefits	3	4
Uncertain tax benefits reconciliation
Balance as of January 1	34	32
Increase due to current year positions	4	8
Decrease due to prior year positions	(8)	0
Decrease due to settlements and payments	0	(6)
Uncertain tax benefits as of December 31	$ 30	$ 34

Stock-Based Compensation - Long-Term Incentive Plan (Details) - shares	Apr. 27, 2017	Dec. 31, 2017	Dec. 31, 2016
NRG LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase in the number of shares available for issuance	3,000,000
Number of shares authorized for issuance under plan		25,000,000	22,000,000
Number of shares available for grant under plan		8,724,595	7,487,058
NRG GenOn LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance under plan		0	5,558,390
Number of shares available for grant under plan		1,369,880	960,904

Stock-Based Compensation - Non-Qualified Stock Options (Details) - NQSOs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock-Based Compensation
Award vesting period	3 years
Shares granted during the period	0	0	0
Maximum contractual term for outstanding options (in years)	10 years
NQSO activity and changes
Outstanding at the beginning of the period (in shares)	1,522,919
Forfeited (in shares)	(50,001)
Exercised (in shares)	(187,060)	0
Outstanding at the end of the period (in shares)	1,285,858.000000	1,522,919
Exercisable at the end of the period (in shares)	1,285,858
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding (in usd per share)	$ 25.03
Forfeited (in usd per share)	29.35
Exercised (in usd per share)	20.71
Outstanding (in usd per share)	25.49	$ 25.03
Exercisable (in usd per share)	$ 25.49
Weighted Average Remaining Contractual Term, Outstanding	3 years	3 years
Weighted Average Remaining Contractual Term, Exercisable	3 years
Aggregate Intrinsic Value, Outstanding	$ 6	$ 0
Aggregate Intrinsic Value, Exercisable	6
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures
Total intrinsic value of options exercised	1	0	$ 2
Cash received from options exercised	$ 4	$ 0	$ 9
GenOn Employees
NQSO activity and changes
Exercised (in shares)	(51,207,000,000)
Outstanding at the end of the period (in shares)	51,207
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Shares vested (in shares)	51,207,000,000

Stock-Based Compensation - Restricted Stock Units (RSUs (Details) - RSUs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock-Based Compensation
Award vesting period	3 years
Units
Non-vested at beginning of period (in shares)	1,980,141
Granted (in shares)	1,247,075
Forfeited (in shares)	(176,132)
Vested (in shares)	(673,271)
Non-vested at end of period (in shares)	2,377,813.000000	1,980,141
Weighted Average Grant-Date Fair Value per Unit
Non-vested at beginning of period (in usd per share)	$ 19.29
Granted (in usd per share)	12.44	$ 11.54	$ 27.31
Forfeited (in usd per share)	14.98
Vested (in usd per share)	23.65
Non-vested at end of period (in usd per share)	$ 14.63	$ 19.29
Vested in period, fair value	$ 19	$ 11	$ 10
GenOn Employees
Units
Non-vested at end of period (in shares)	20,822

Stock-Based Compensation - Deferred Stock Units, DSUs (Details) - DSUs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Units
Balance outstanding at the beginning of the period (in shares)	453,674
Granted (in shares)	120,251
Converted to Common Stock (in shares)	(146,777)
Balance outstanding at the end of the period (in shares)	427,148.000000	453,674
Weighted Average Grant-Date Fair Value per Unit
Balance outstanding at the beginning of the period, (in usd per share)	$ 21.54
Granted (in usd per share)	16.76	$ 16.85	$ 25.14
Converted to Common Stock (in usd per share)	17.62
Balance outstanding at the end of the period (in usd per share)	$ 21.54	$ 21.54
Aggregate intrinsic value for DSUs outstanding	$ 12	$ 6	$ 5
Aggregate intrinsic values for DSUs converted to common stock during the period	$ 4	$ 1	$ 0
GenOn Employees
Units
Granted (in shares)	0

Stock-Based Compensation - Performance Stock Units, RPSUs and MSUs (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Performance Stock Units
Units
Non-vested at beginning of period (in shares)	1,282,588
Granted (in shares)	738,830
Forfeited (in shares)	(162,597)
Non-vested at end of period (in shares)	1,858,821.000000	1,282,588
Weighted Average Grant-Date Fair Value per Unit
Non-vested at beginning of period (in usd per share)	$ 21.47
Granted (in usd per share)	15.91
Forfeited (in usd per share)	31.85
Non-vested at end of period (in usd per share)	$ 18.27	$ 21.47
Performance Stock Units \| GenOn Employees
Units
Granted (in shares)	0
RPSUs
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility	43.96%
Expected term (in years)	3 years
Risk free rate	1.50%
MSUs
Stock-Based Compensation
Plan Description	MSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's 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 common stock to be paid as of the vesting date for each MSU is : (i) zero shares, if the TSR has decreased by more than 25% over the performance period, (ii) three-quarters of one share, if the TSR has decreased by 25% over the performance period; (iii) interpolated between three-quarters of one share and one share, if the TSR has decreased less than 25% over the performance period; (iv) one share, if there is no change in TSR over the performance period; (v) interpolated between one share and two shares, if TSR increases less than 100% during the performance period; and (vi) two shares, if the TSR increases 100% over the performance period. 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.
Weighted Average Grant-Date Fair Value per Unit
Granted (in usd per share)		$ 14.73	$ 26.68
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility		34.33%
Expected term (in years)		3 years
Risk free rate		1.31%

Stock-Based Compensation - Supplemental Information (Details) - USD ($) $ in Millions	5 Months Ended	12 Months Ended
	Jun. 13, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock-Based Compensation
Minimum tax withholdings		$ 5.0	$ 5.0	$ 21.0
Compensation Expense		44.0	23.0	40.0
Tax detriment recognized		(5.0)	(4.0)	(12.0)
Unrecognized Total Cost		37.0
GenOn
Stock-Based Compensation
Compensation Expense	$ 1.0	1.0	1.0	1.0
NQSOs
Stock-Based Compensation
Compensation Expense		0.0	0.0	0.0
Unrecognized Total Cost		$ 0.0
Weighted Average Recognition Period Remaining (In years)		0 years
Award vesting period		3 years
RSUs
Stock-Based Compensation
Compensation Expense		$ 17.0	13.0	22.0
Unrecognized Total Cost		$ 13.0
Weighted Average Recognition Period Remaining (In years)		1 year 4 months 13 days
Award vesting period		3 years
DSUs
Stock-Based Compensation
Compensation Expense		$ 2.0	2.0	2.0
Unrecognized Total Cost		$ 0.0
Weighted Average Recognition Period Remaining (In years)		0 years
MSUs
Stock-Based Compensation
Compensation Expense		$ 6.0	3.0	16.0
Unrecognized Total Cost		$ 4.0
Weighted Average Recognition Period Remaining (In years)		9 months 26 days
RPSUs
Stock-Based Compensation
Compensation Expense		$ 4.0	0.0	0.0
Unrecognized Total Cost		$ 6.0
Weighted Average Recognition Period Remaining (In years)		1 year 11 months 27 days
PRSUs
Stock-Based Compensation
Compensation Expense		$ 15.0	$ 5.0	$ 0.0
Unrecognized Total Cost		$ 14.0
Weighted Average Recognition Period Remaining (In years)		1 year 6 months 4 days
Phantom Share Units (PSUs)
Stock-Based Compensation
Award vesting period		3 years

Related Party Transactions - Summary of Material Related Party Transactions With Third Party Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	$ 8	$ 7	$ 8
Gladstone
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	3	2	4
GenConn
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	$ 5	$ 5	$ 4

Related Party Transactions - Service Agreement and Transition Service Agreement with GeOn (Details) - USD ($) $ in Millions			1 Months Ended	7 Months Ended	12 Months Ended
	Jun. 14, 2017	Jun. 12, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Other income - affiliate			$ 84.0		$ 87.0	$ 193.0	$ 193.0
Services Agreement \| GenOn
Related Party Transaction [Line Items]
Service fees					193.0
Reserve against affiliate receivable			12.0	$ 12.0	12.0
Services Agreement \| Restructuring Support Agreement
Related Party Transaction [Line Items]
Shared services annualized rate		$ 84.0	84.0	84.0	84.0
Monthly cost of shared services	$ 5.0		7.0	$ 5.0
Credit applied		$ 28.0	3.5		28.0
Transition Services Agreement \| Restructuring Support Agreement
Related Party Transaction [Line Items]
Credit applied			$ 28.0
Transition Services Agreement \| Restructuring Support Agreement \| GenOn
Related Party Transaction [Line Items]
Other income - affiliate					87.0
Shared service, selling, general and administrative					$ 42.0

Related Party Transactions - Credit Agreement with GenOn and Commercial Operations Agreement (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Long-term debt	$ 16,633,000,000	$ 16,704,000,000
Cash collateral posted in support of energy risk management activities	171,000,000	150,000,000
GenOn
Related Party Transaction [Line Items]
Cash collateral posted in support of energy risk management activities	32,000,000	79,000,000
Revolving Credit Facility \| Intercompany Credit Agreement \| GenOn
Related Party Transaction [Line Items]
Revolving credit facility	500,000,000
Letters of credit outstanding under revolver	92,000,000	272,000,000
Long-term debt	125,000,000	$ 0
Revolving Credit Facility \| Restructuring Support Agreement, Letter of Credit Credit Facility \| GenOn
Related Party Transaction [Line Items]
Revolving credit facility	$ 330,000,000
Line of credit facility cash collateralized percentage required	103.00%

Commitments and Contingencies - Operating Leases (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Coal, Gas and Transportation Commitments

Out-of-market contracts, net

$ 207

$ 230

Future commitments under coal, gas and transportation contractual agreements

Future minimum sublease rentals

Powerton and Joliet

Future commitments under coal, gas and transportation contractual agreements

228

240

Other Leased Property

Coal, Gas and Transportation Commitments

Lease expense

$ 96

$ 97

Future commitments under coal, gas and transportation contractual agreements

479

^[1]

$ 841

EME Project Financings

Coal, Gas and Transportation Commitments

Leased Interest

100.00%

Out-of-market contracts, net

$ 159

Lease expense

$ 14

[1]	Amounts in the table exclude future sublease income of $49 million associated with long-term leases for office locations.

Commitments and Contingencies - Transportation and Purchased Power Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Minimum purchase commitment
2018	$ 21
2019	14
2020	12
2021	11
2022	10
Thereafter	0
Total	$ 68
Maximum remaining term under individual purchased power contract (in years)	5 years
Coal, Gas and Transportation Commitments
Commitments and Contingencies
Purchases	$ 1,200	$ 1,200	$ 1,800
Minimum purchase commitment
2018	527
2019	188
2020	150
2021	112
2022	103
Thereafter	296
Total	$ 1,376

Commitments and Contingencies - Contingencies (Details 1)		1 Months Ended		7 Months Ended	12 Months Ended	29 Months Ended	101 Months Ended
	Jun. 01, 2001	Feb. 20, 2018 USD ($)	Jun. 30, 2010 Plaintiff	Mar. 10, 2010 Claim	Dec. 31, 2017 USD ($) lawsuit	Jul. 31, 2013 Claim	Dec. 31, 2017 USD ($) lawsuit Plaintiff	Dec. 31, 2012 Claim
Loss Contingencies [Line Items]
Nuclear insurance liability limit per incident					$ 13,440,000,000		$ 13,440,000,000
Required nuclear liability insurance					450,000,000		450,000,000
Nuclear financial protection pool mandated by the Price-Anderson Act					13,000,000,000		13,000,000,000
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident					$ 127,000,000		$ 127,000,000
Maximum assessment, administrative fee (as percent)					5.00%		5.00%
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident					$ 19,000,000		$ 19,000,000
Nuclear operator maximum annual assessment					$ 8,000,000		$ 8,000,000
44% maximum assessment					44.00%		44.00%
Maximum liability per nuclear incident					$ 112,000,000		$ 112,000,000
Mutual property insurance additional blanket policy property coverage					1,250,000,000		1,250,000,000
Nuclear property insurance coverage limit per individual insured					1,500,000,000		1,500,000,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery					2,520,000		2,520,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss					$ 1,980,000		$ 1,980,000
Multiplier that the industry mutual insurance company may assess against insureds premium					10		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
Telephone Consumer Protection Act Purported Class Actions
Loss Contingencies [Line Items]
Number of cases \| lawsuit					3
Damages sought					$ 1,500
Telephone Consumer Protection Act Purported Class Actions \| California
Loss Contingencies [Line Items]
Number of cases \| lawsuit							1
Telephone Consumer Protection Act Purported Class Actions \| New Jersey
Loss Contingencies [Line Items]
Number of cases \| lawsuit							2
CDWR and SDGE v Sunrise Power
Loss Contingencies [Line Items]
Damages sought					$ 1,200,000
Power Purchase Agreement (PPA) period	10 years
Remaining Term					70 months
Nuclear Event
Loss Contingencies [Line Items]
Total nuclear property insurance coverage					$ 2,750,000,000		$ 2,750,000,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery					274,400,000		274,400,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss					215,600,000		215,600,000
Non-nuclear Event
Loss Contingencies [Line Items]
Total nuclear property insurance coverage					1,500,000,000		1,500,000,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery					183,500,000		183,500,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss					144,000,000		$ 144,000,000
Midwest Generation New Source Review
Loss Contingencies [Line Items]
Claims dismissed \| Claim				9		9
Pending claims \| Claim				10		10		1
Number of plaintiffs \| Plaintiff			1				1
Midwest Generation New Source Review \| Minimum
Loss Contingencies [Line Items]
Pending claims \| Plaintiff			1
Midwest Generation New Source Review \| Maximum
Loss Contingencies [Line Items]
Pending claims \| Plaintiff			10
Lignite Contract with Texas Westmoreland Coal Co. \| Texas Westmoreland Coal Co.
Loss Contingencies [Line Items]
Bond obligation					$ 95,500,000		$ 95,500,000
Subsequent Event
Loss Contingencies [Line Items]
Agreement to pay the State of Illinois and Federal Government		$ 500,000

Commitments and Contingencies - Contingencies (Details 2)				1 Months Ended
	Feb. 16, 2018 USD ($)	Nov. 07, 2017 USD ($)	Sep. 07, 2017 USD ($)	May 31, 2016 case	Jun. 30, 2013 case	Jun. 14, 2017	Dec. 13, 2016	Sep. 30, 2012 Claim
Morgantown V. GenOn Mid-Atlantic
Loss Contingencies
Damages sought		$ 0
BTEC New Albany v. NRG Texas Power
Loss Contingencies
Damages sought			$ 48,000,000
Natural Gas Litigation
Loss Contingencies
Number of cases \| case				1
Claims dismissed \| case					1
Pending claims \| Claim								5
GenOn Senior Notes Due in 2017
Loss Contingencies
Interest rate, stated percentage						7.875%
GenOn Senior Notes Due in 2017 \| Non Recourse Debt
Loss Contingencies
Interest rate, stated percentage							7.875%
GenOn senior notes, due 2018
Loss Contingencies
Interest rate, stated percentage						9.50%
GenOn senior notes, due 2018 \| Non Recourse Debt
Loss Contingencies
Interest rate, stated percentage							9.50%
GenOn senior notes, due 2020
Loss Contingencies
Interest rate, stated percentage						9.875%
GenOn senior notes, due 2020 \| Non Recourse Debt
Loss Contingencies
Interest rate, stated percentage							9.875%
GenOn Americas Generation Senior Notes Due in 2021
Loss Contingencies
Interest rate, stated percentage						8.50%
GenOn Americas Generation Senior Notes Due in 2021 \| Non Recourse Debt
Loss Contingencies
Interest rate, stated percentage							8.50%
GenOn Americas Generation senior notes, due 2031
Loss Contingencies
Interest rate, stated percentage						9.125%
GenOn Americas Generation senior notes, due 2031 \| Non Recourse Debt
Loss Contingencies
Interest rate, stated percentage							9.125%
Subsequent Event \| Natixis V. GenOn Mid-Atlantic
Loss Contingencies
Damages sought	$ 34,000,000

Regulatory Matters (Details) $ in Millions	Dec. 20, 2013 USD ($)
GenOn
Regulatory Assets [Line Items]
Regulatory payments sought	$ 22

Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
Cash Flow Information (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Interest paid, net of amount capitalized	$ 868	$ 890	$ 924
Income taxes paid	9	14	12
Additions/(decrease) to fixed assets for accrued capital expenditures	70	$ 35	(44)
Income taxes paid	11		13
Income tax refunds received	$ 2		$ 1

Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
Guarantees (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Guarantor Obligations
Under 1 Year	$ 1,467
1-3 Years	98
3-5 Years	264
Over 5 Years	761
Guarantees by Remaining Maturity, Total	2,590	$ 2,767
Letters of credit and surety bonds
Guarantor Obligations
Under 1 Year	1,467
1-3 Years	66
3-5 Years	7
Over 5 Years	93
Guarantees by Remaining Maturity, Total	$ 1,633	1,837
Letters of credit and surety bonds, maximum expiration period (in years)	1 year
Asset sales guarantee obligations
Guarantor Obligations
Under 1 Year	$ 0
1-3 Years	0
3-5 Years	257
Over 5 Years	55
Guarantees by Remaining Maturity, Total	312	677
Other guarantees
Guarantor Obligations
Under 1 Year	0
1-3 Years	32
3-5 Years	0
Over 5 Years	613
Guarantees by Remaining Maturity, Total	645	253
Eliminations \| Letters of credit and surety bonds
Guarantor Obligations
Guarantees by Remaining Maturity, Total	$ 92	$ 272

Jointly Owned Plants (Details) $ in Millions	Dec. 31, 2017 USD ($)
South Texas Project Units 1 and 2, Bay City, TX
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	44.00%
Property, Plant & Equipment	$ 395
Accumulated Depreciation	(207)
Construction in Progress	$ 7
Big Cajun II Unit 3, New Roads, LA
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	58.00%
Property, Plant & Equipment	$ 202
Accumulated Depreciation	(132)
Construction in Progress	$ 0
Cedar Bayou Unit 4, Baytown, TX
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	50.00%
Property, Plant & Equipment	$ 215
Accumulated Depreciation	(75)
Construction in Progress	$ 7
Keystone, Shelocta, PA
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	3.70%
Property, Plant & Equipment	$ 12
Accumulated Depreciation	0
Construction in Progress	$ 1
Conemaugh, New Florence, PA
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	3.72%
Property, Plant & Equipment	$ 14
Accumulated Depreciation	0
Construction in Progress	$ 1

Unaudited Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 2,497	$ 3,049	$ 2,701	$ 2,382	$ 2,184	$ 3,421	$ 2,248	$ 2,659	$ 10,629	$ 10,512	$ 12,328
Operating (loss)/ income	(1,345)	376	343	39	(658)	429	164	331	(587)	266	(4,051)
Net (loss)/income from continuing operations	(1,667)	190	99	(170)	(891)	128	(163)	(57)	(1,548)	(983)	(6,331)
(Loss)/income from discontinued operations, net of income tax	13	(27)	(741)	(34)	(164)	265	(113)	104	(789)	92	(105)
Net Loss	(1,655)	163	(642)	(203)	(1,055)	393	(276)	47	(2,337)	(891)	(6,436)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(120)	(8)	(16)	(40)	(68)	(9)	(5)	(35)	(184)	(117)	(54)
Net (loss)/income attributable to NRG Energy, Inc.	(1,535)	171	(626)	(163)	(987)	402	(271)	82	(2,153)	(774)	(6,382)
(Loss)/income available to Common Stockholders	$ (1,535)	$ 171	$ (626)	$ (163)	$ (987)	$ 402	$ (193)	$ 77	$ (2,153)	$ (701)	$ (6,402)
Weighted average number of common shares outstanding — basic (in shares)	317	317	316	316	316	316	315	315
Income/(loss) from discontinued operations per weighted average common share — basic (in usd per share)	$ 0.04	$ (0.09)	$ (2.34)	$ (0.11)	$ (0.52)	$ 0.84	$ (0.36)	$ 0.33	$ (2.49)	$ 0.29	$ (0.32)
Net (loss)/income per weighted average common share — basic (in usd per share)	$ (4.84)	$ 0.54	$ (1.98)	$ (0.52)	$ (3.12)	$ 1.27	$ (0.61)	$ 0.24
Weighted average number of common shares outstanding — diluted (in shares)	317	322	316	316	316	317	315	315
Income/(loss) from discontinued operations per weighted average common share — diluted (in usd per share)	$ 0.04	$ (0.08)	$ (2.34)	$ (0.11)	$ (0.52)	$ 0.84	$ (0.36)	$ 0.33
Net (loss)/income per weighted average common share — diluted (in usd per share)	$ (4.84)	$ 0.53	$ (1.98)	$ (0.52)	$ (3.12)	$ 1.27	$ (0.61)	$ 0.24

Condensed Consolidating Financial Information (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument
Long-term debt	$ 16,633	$ 16,704
Recourse Debt
Debt Instrument
Long-term debt	7,182	$ 7,795
Senior Notes \| Recourse Debt
Debt Instrument
Long-term debt	$ 4,800

Condensed Consolidating Financial Information - Statements of Operations (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended									12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Revenues
Total operating revenues		$ 2,497	$ 3,049	$ 2,701	$ 2,382	$ 2,184	$ 3,421	$ 2,248	$ 2,659		$ 10,629	$ 10,512	$ 12,328
Operating Costs and Expenses
Cost of operations											7,536	7,301	9,000
Depreciation and amortization											1,056	1,172	1,351
Impairment losses											1,709	702	4,860
Selling, general and administrative											907	1,095	1,228
Reorganization costs											44
Development costs											67	89	154
Total operating costs and expenses											11,319	10,359	16,593
Other income - affiliate	$ 84										87	193	193
Gain on sale of assets											16	(80)	0
Gain on postretirement benefits curtailment											0	0	21
Operating (Loss)/Income		(1,345)	376	343	39	(658)	429	164	331		(587)	266	(4,051)
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries											0	0	0
Equity in (losses)/earnings of unconsolidated affiliates											31	27	36
Impairment losses on investments										$ (56)	(79)	(268)	(56)
Other income, net											38	34	26
Loss on sale of equity method investment											0	0	(14)
Net (loss)/gain on debt extinguishment											(53)	(142)	10
Interest expense											(890)	(895)	(937)
Total other expense											(953)	(1,244)	(935)
Loss from Continuing Operations Before Income Taxes											(1,540)	(978)	(4,986)
Income tax (benefit)/expense											8	5	1,345
Net Loss from Continuing Operations		(1,667)	190	99	(170)	(891)	128	(163)	(57)		(1,548)	(983)	(6,331)
(Loss)/income from discontinued operations, net of income tax		13	(27)	(741)	(34)	(164)	265	(113)	104		(789)	92	(105)
Net Loss		(1,655)	163	(642)	(203)	(1,055)	393	(276)	47		(2,337)	(891)	(6,436)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests		(120)	(8)	(16)	(40)	(68)	(9)	(5)	(35)		(184)	(117)	(54)
Net Loss Attributable to NRG Energy, Inc.		$ (1,535)	$ 171	$ (626)	$ (163)	$ (987)	$ 402	$ (271)	$ 82		(2,153)	(774)	(6,382)
Eliminations
Operating Revenues
Total operating revenues											(252)	(219)	(94)
Operating Costs and Expenses
Cost of operations											(249)	(223)	(94)
Depreciation and amortization											0	0	0
Impairment losses											0	0	0
Selling, general and administrative											(3)	0	0
Reorganization costs											0
Development costs											0	0	0
Total operating costs and expenses											(252)	(223)	(94)
Other income - affiliate											0	0	0
Gain on sale of assets											0	0
Gain on postretirement benefits curtailment													0
Operating (Loss)/Income											0	4	0
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries											1,249	(132)	2,910
Equity in (losses)/earnings of unconsolidated affiliates											(60)	(10)	(9)
Impairment losses on investments											0	0	0
Other income, net											0	(2)	0
Loss on sale of equity method investment													0
Net (loss)/gain on debt extinguishment											0	0	0
Interest expense											0	0	0
Total other expense											1,189	(144)	2,901
Loss from Continuing Operations Before Income Taxes											1,189	(140)	2,901
Income tax (benefit)/expense											0	62	53
Net Loss from Continuing Operations											1,189	(202)	2,848
(Loss)/income from discontinued operations, net of income tax											0	0	0
Net Loss											1,189	(202)	2,848
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(60)	(70)	(62)
Net Loss Attributable to NRG Energy, Inc.											1,249	(132)	2,910
Guarantor Subsidiaries
Operating Revenues
Total operating revenues											7,182	7,509	9,881
Operating Costs and Expenses
Cost of operations											5,373	5,402	7,610
Depreciation and amortization											405	565	751
Impairment losses											1,463	378	4,494
Selling, general and administrative											371	415	468
Reorganization costs											6
Development costs											0	0	0
Total operating costs and expenses											7,618	6,760	13,323
Other income - affiliate											0	0	0
Gain on sale of assets											4	(1)
Gain on postretirement benefits curtailment													0
Operating (Loss)/Income											(432)	748	(3,442)
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries											(1,162)	(176)	(109)
Equity in (losses)/earnings of unconsolidated affiliates											0	5	8
Impairment losses on investments											0	0	0
Other income, net											9	4	4
Loss on sale of equity method investment													0
Net (loss)/gain on debt extinguishment											0	0	0
Interest expense											(14)	(15)	(14)
Total other expense											(1,167)	(182)	(111)
Loss from Continuing Operations Before Income Taxes											(1,599)	566	(3,553)
Income tax (benefit)/expense											(598)	(1)	(1,104)
Net Loss from Continuing Operations											(1,001)	567	(2,449)
(Loss)/income from discontinued operations, net of income tax											0	0	0
Net Loss											(1,001)	567	(2,449)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											0	0	0
Net Loss Attributable to NRG Energy, Inc.											(1,001)	567	(2,449)
Non-Guarantor Subsidiaries
Operating Revenues
Total operating revenues											3,699	3,222	2,541
Operating Costs and Expenses
Cost of operations											2,353	2,080	1,470
Depreciation and amortization											619	581	580
Impairment losses											246	324	366
Selling, general and administrative											146	192	204
Reorganization costs											0
Development costs											49	59	61
Total operating costs and expenses											3,413	3,236	2,681
Other income - affiliate											0	0	0
Gain on sale of assets											12	0
Gain on postretirement benefits curtailment													21
Operating (Loss)/Income											298	(14)	(119)
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries											(113)	(5)	(1)
Equity in (losses)/earnings of unconsolidated affiliates											95	36	37
Impairment losses on investments											(75)	(252)	(25)
Other income, net											17	23	21
Loss on sale of equity method investment													0
Net (loss)/gain on debt extinguishment											(4)	(4)	(9)
Interest expense											(424)	(396)	(366)
Total other expense											(504)	(598)	(343)
Loss from Continuing Operations Before Income Taxes											(206)	(612)	(462)
Income tax (benefit)/expense											(10)	7	(93)
Net Loss from Continuing Operations											(196)	(619)	(369)
(Loss)/income from discontinued operations, net of income tax											(160)	81	(115)
Net Loss											(356)	(538)	(484)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(108)	(103)	(23)
Net Loss Attributable to NRG Energy, Inc.											(248)	(435)	(461)
NRG Energy, Inc. (Note Issuer)
Operating Revenues
Total operating revenues											0	0	0
Operating Costs and Expenses
Cost of operations											59	42	14
Depreciation and amortization											32	26	20
Impairment losses											0	0	0
Selling, general and administrative											393	488	556
Reorganization costs											38
Development costs											18	30	93
Total operating costs and expenses											540	586	683
Other income - affiliate											87	193	193
Gain on sale of assets											0	(79)
Gain on postretirement benefits curtailment													0
Operating (Loss)/Income											(453)	(472)	(490)
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries											26	313	(2,800)
Equity in (losses)/earnings of unconsolidated affiliates											(4)	(4)	0
Impairment losses on investments											(4)	(16)	(31)
Other income, net											12	9	1
Loss on sale of equity method investment													(14)
Net (loss)/gain on debt extinguishment											(49)	(138)	19
Interest expense											(452)	(484)	(557)
Total other expense											(471)	(320)	(3,382)
Loss from Continuing Operations Before Income Taxes											(924)	(792)	(3,872)
Income tax (benefit)/expense											616	(63)	2,489
Net Loss from Continuing Operations											(1,540)	(729)	(6,361)
(Loss)/income from discontinued operations, net of income tax											(629)	11	10
Net Loss											(2,169)	(718)	(6,351)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests											(16)	56	31
Net Loss Attributable to NRG Energy, Inc.											$ (2,153)	$ (774)	$ (6,382)

Condensed Consolidating Financial Information - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net (Loss)/Income	$ (1,655)	$ 163	$ (642)	$ (203)	$ (1,055)	$ 393	$ (276)	$ 47	$ (2,337)	$ (891)	$ (6,436)
Unrealized gain on derivatives, net									13	35	(15)
Foreign currency translation adjustments, net									12	(1)	(11)
Available-for-sale securities, net									(8)	1	17
Defined benefit plan, net									46	3	10
Other comprehensive income									63	38	1
Comprehensive Loss									(2,274)	(853)	(6,435)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests									(179)	(117)	(73)
Comprehensive Loss Attributable to NRG Energy, Inc.									(2,095)	(736)	(6,362)
Dividends for preferred shares									0	5	20
Gain on redemption of preferred shares									0	(78)	0
Comprehensive Loss Available for Common Stockholders									(2,095)	(663)	(6,382)
Eliminations
Net (Loss)/Income									1,189	(202)	2,848
Unrealized gain on derivatives, net									(26)	(86)	(39)
Foreign currency translation adjustments, net									(1)	2	0
Available-for-sale securities, net									0	0	0
Defined benefit plan, net									0	33	89
Other comprehensive income									(27)	(51)	50
Comprehensive Loss									1,162	(253)	2,898
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests									(60)	(70)	(62)
Comprehensive Loss Attributable to NRG Energy, Inc.									1,222	(183)	2,960
Dividends for preferred shares										0	0
Gain on redemption of preferred shares										0
Comprehensive Loss Available for Common Stockholders										(183)	2,960
Guarantor Subsidiaries
Net (Loss)/Income									(1,001)	567	(2,449)
Unrealized gain on derivatives, net									1	0	(8)
Foreign currency translation adjustments, net									6	(1)	0
Available-for-sale securities, net									0	0	0
Defined benefit plan, net									(24)	34	(22)
Other comprehensive income									(17)	33	(30)
Comprehensive Loss									(1,018)	600	(2,479)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Comprehensive Loss Attributable to NRG Energy, Inc.									(1,018)	600	(2,479)
Dividends for preferred shares										0	0
Gain on redemption of preferred shares										0
Comprehensive Loss Available for Common Stockholders										600	(2,479)
Non-Guarantor Subsidiaries
Net (Loss)/Income									(356)	(538)	(484)
Unrealized gain on derivatives, net									13	32	(16)
Foreign currency translation adjustments, net									7	(1)	(7)
Available-for-sale securities, net									0	0	(1)
Defined benefit plan, net									29	(13)	(15)
Other comprehensive income									49	18	(39)
Comprehensive Loss									(307)	(520)	(523)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests									(103)	(103)	(42)
Comprehensive Loss Attributable to NRG Energy, Inc.									(204)	(417)	(481)
Dividends for preferred shares										0	0
Gain on redemption of preferred shares										0
Comprehensive Loss Available for Common Stockholders										(417)	(481)
NRG Energy, Inc. (Note Issuer)
Net (Loss)/Income									(2,169)	(718)	(6,351)
Unrealized gain on derivatives, net									25	89	48
Foreign currency translation adjustments, net									0	(1)	(4)
Available-for-sale securities, net									(8)	1	18
Defined benefit plan, net									41	(51)	(42)
Other comprehensive income									58	38	20
Comprehensive Loss									(2,111)	(680)	(6,331)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests									(16)	56	31
Comprehensive Loss Attributable to NRG Energy, Inc.									$ (2,095)	(736)	(6,362)
Dividends for preferred shares										5	20
Gain on redemption of preferred shares										(78)
Comprehensive Loss Available for Common Stockholders										$ (663)	$ (6,382)

Condensed Consolidating Financial Information - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 991	$ 938	$ 853
Funds deposited by counterparties	37	2	55
Restricted cash	508	446	414
Accounts receivable - trade	1,079	1,058
Inventory	532	721
Derivative instruments	626	1,067
Cash collateral posted in support of energy risk management activities	171	150
Accounts receivable - affiliate	95	114
Current assets held-for-sale	115	9
Prepayments and other current assets	261	290
Current assets - discontinued operations	0	1,919
Total current assets	4,415	6,714
Net Property, Plant and Equipment	13,908	15,369
Other Assets
Investment in subsidiaries	0	0
Equity investments in affiliates	1,038	1,120
Notes receivable, less current portion	2	16
Goodwill	539	662
Intangible assets, net	1,746	1,973
Nuclear decommissioning trust fund	692	610
Deferred income taxes	134	225
Derivative instruments	172	181
Non-current assets held-for-sale	43	10
Other non-current assets	629	841
Non-current assets - discontinued operations	0	2,961
Total other assets	4,995	8,599
Total Assets	23,318	30,682
Current Liabilities
Current portion of long-term debt and capital leases	688	516
Accounts payable	881	782
Accounts payable - affiliate	33	31
Derivative instruments	555	1,092
Cash collateral received in support of energy risk management activities	37	81
Accrued interest expense	156	180
Current liabilities - held for sale	72	0
Other accrued expenses and other current liabilities	734	810
Other accrued expenses and other current liabilities - affiliate	161	0
Current liabilities - discontinued operations	0	1,210
Total current liabilities	3,317	4,702
Other Liabilities
Long-term debt and capital leases	15,716	15,957
Nuclear decommissioning reserve	269	287
Nuclear decommissioning trust liability	415	339
Postretirement and other benefit obligations	458	510
Deferred income taxes	21	20
Derivative instruments	197	284
Out-of-market contracts, net	207	230
Non-current liabilities held-for-sale	8	11
Other non-current liabilities	664	666
Non-current liabilities - discontinued operations	0	3,184
Total non-current liabilities	17,955	21,488
Total Liabilities	21,272	26,190
Redeemable noncontrolling interest in subsidiaries	78	46	29	$ 19
Total Stockholders' Equity	1,968	4,446	$ 5,434	$ 11,676
Total Liabilities and Stockholders' Equity	23,318	30,682
Eliminations
Current Assets
Cash and cash equivalents	0	0
Funds deposited by counterparties	0	0
Restricted cash	0	0
Accounts receivable - trade	0	0
Inventory	0	0
Derivative instruments	(88)	(92)
Cash collateral posted in support of energy risk management activities	0	0
Accounts receivable - affiliate	(698)	(139)
Current assets held-for-sale	0	0
Prepayments and other current assets	0	0
Current assets - discontinued operations		0
Total current assets	(786)	(231)
Net Property, Plant and Equipment	(26)	(27)
Other Assets
Investment in subsidiaries	(7,503)	(11,363)
Equity investments in affiliates	0	0
Notes receivable, less current portion	(36)	76
Goodwill	0	0
Intangible assets, net	(3)	(3)
Nuclear decommissioning trust fund	0	0
Deferred income taxes	0	0
Derivative instruments	(20)	(43)
Non-current assets held-for-sale	0	0
Other non-current assets	0	0
Non-current assets - discontinued operations		0
Total other assets	(7,562)	(11,333)
Total Assets	(8,374)	(11,591)
Current Liabilities
Current portion of long-term debt and capital leases	(36)	76
Accounts payable	0	0
Accounts payable - affiliate	(698)	(79)
Derivative instruments	(88)	(92)
Cash collateral received in support of energy risk management activities	0	0
Accrued interest expense	0	0
Current liabilities - held for sale	0
Other accrued expenses and other current liabilities	0	0
Other accrued expenses and other current liabilities - affiliate	0
Current liabilities - discontinued operations		0
Total current liabilities	(822)	(95)
Other Liabilities
Long-term debt and capital leases	0	0
Nuclear decommissioning reserve	0	0
Nuclear decommissioning trust liability	0	0
Postretirement and other benefit obligations	0	0
Deferred income taxes	0	0
Derivative instruments	(20)	(43)
Out-of-market contracts, net	0	0
Non-current liabilities held-for-sale	0	0
Other non-current liabilities	0	0
Non-current liabilities - discontinued operations		0
Total non-current liabilities	(20)	(43)
Total Liabilities	(842)	(138)
Redeemable noncontrolling interest in subsidiaries	0	0
Total Stockholders' Equity	(7,532)	(11,453)
Total Liabilities and Stockholders' Equity	(8,374)	(11,591)
Guarantor Subsidiaries
Current Assets
Cash and cash equivalents	0	0
Funds deposited by counterparties	37	2
Restricted cash	4	11
Accounts receivable - trade	769	734
Inventory	339	482
Derivative instruments	625	962
Cash collateral posted in support of energy risk management activities	170	116
Accounts receivable - affiliate	712	307
Current assets held-for-sale	8	0
Prepayments and other current assets	116	76
Current assets - discontinued operations		0
Total current assets	2,780	2,690
Net Property, Plant and Equipment	2,527	4,219
Other Assets
Investment in subsidiaries	(106)	1,090
Equity investments in affiliates	0	(13)
Notes receivable, less current portion	0	0
Goodwill	360	359
Intangible assets, net	458	592
Nuclear decommissioning trust fund	692	610
Deferred income taxes	377	3
Derivative instruments	121	144
Non-current assets held-for-sale	0	0
Other non-current assets	51	67
Non-current assets - discontinued operations		0
Total other assets	1,953	2,852
Total Assets	7,260	9,761
Current Liabilities
Current portion of long-term debt and capital leases	0	0
Accounts payable	546	501
Accounts payable - affiliate	752	753
Derivative instruments	535	947
Cash collateral received in support of energy risk management activities	37	81
Accrued interest expense	3	3
Current liabilities - held for sale	0
Other accrued expenses and other current liabilities	288	313
Other accrued expenses and other current liabilities - affiliate	0
Current liabilities - discontinued operations		0
Total current liabilities	2,161	2,598
Other Liabilities
Long-term debt and capital leases	244	244
Nuclear decommissioning reserve	269	287
Nuclear decommissioning trust liability	415	339
Postretirement and other benefit obligations	118	113
Deferred income taxes	112	186
Derivative instruments	110	157
Out-of-market contracts, net	66	80
Non-current liabilities held-for-sale	0	0
Other non-current liabilities	295	283
Non-current liabilities - discontinued operations		0
Total non-current liabilities	1,629	1,689
Total Liabilities	3,790	4,287
Redeemable noncontrolling interest in subsidiaries	0	0
Total Stockholders' Equity	3,470	5,474
Total Liabilities and Stockholders' Equity	7,260	9,761
Non-Guarantor Subsidiaries
Current Assets
Cash and cash equivalents	348	615
Funds deposited by counterparties	0	0
Restricted cash	504	435
Accounts receivable - trade	306	321
Inventory	193	239
Derivative instruments	80	196
Cash collateral posted in support of energy risk management activities	1	34
Accounts receivable - affiliate	210	(254)
Current assets held-for-sale	107	9
Prepayments and other current assets	118	152
Current assets - discontinued operations		1,919
Total current assets	1,867	3,666
Net Property, Plant and Equipment	11,169	10,926
Other Assets
Investment in subsidiaries	28	145
Equity investments in affiliates	1,036	1,103
Notes receivable, less current portion	2	16
Goodwill	179	303
Intangible assets, net	1,291	1,384
Nuclear decommissioning trust fund	0	0
Deferred income taxes	(7)	0
Derivative instruments	40	44
Non-current assets held-for-sale	43	10
Other non-current assets	458	446
Non-current assets - discontinued operations		2,961
Total other assets	3,070	6,412
Total Assets	16,106	21,004
Current Liabilities
Current portion of long-term debt and capital leases	667	498
Accounts payable	280	247
Accounts payable - affiliate	(202)	(443)
Derivative instruments	108	237
Cash collateral received in support of energy risk management activities	0	0
Accrued interest expense	56	54
Current liabilities - held for sale	72
Other accrued expenses and other current liabilities	118	155
Other accrued expenses and other current liabilities - affiliate	0
Current liabilities - discontinued operations		1,210
Total current liabilities	1,099	1,958
Other Liabilities
Long-term debt and capital leases	8,733	8,252
Nuclear decommissioning reserve	0	0
Nuclear decommissioning trust liability	0	0
Postretirement and other benefit obligations	1	122
Deferred income taxes	64	125
Derivative instruments	107	170
Out-of-market contracts, net	141	150
Non-current liabilities held-for-sale	8	11
Other non-current liabilities	317	309
Non-current liabilities - discontinued operations		3,184
Total non-current liabilities	9,371	12,323
Total Liabilities	10,470	14,281
Redeemable noncontrolling interest in subsidiaries	78	46
Total Stockholders' Equity	5,558	6,677
Total Liabilities and Stockholders' Equity	16,106	21,004
NRG Energy, Inc.
Current Assets
Cash and cash equivalents	643	323
Funds deposited by counterparties	0	0
Restricted cash	0	0
Accounts receivable - trade	4	3
Inventory	0	0
Derivative instruments	9	1
Cash collateral posted in support of energy risk management activities	0	0
Accounts receivable - affiliate	(129)	200
Current assets held-for-sale	0	0
Prepayments and other current assets	27	62
Current assets - discontinued operations		0
Total current assets	554	589
Net Property, Plant and Equipment	238	251
Other Assets
Investment in subsidiaries	7,581	10,128
Equity investments in affiliates	2	30
Notes receivable, less current portion	36	(76)
Goodwill	0	0
Intangible assets, net	0	0
Nuclear decommissioning trust fund	0	0
Deferred income taxes	(236)	222
Derivative instruments	31	36
Non-current assets held-for-sale	0	0
Other non-current assets	120	328
Non-current assets - discontinued operations		0
Total other assets	7,534	10,668
Total Assets	8,326	11,508
Current Liabilities
Current portion of long-term debt and capital leases	57	(58)
Accounts payable	55	34
Accounts payable - affiliate	181	(200)
Derivative instruments	0	0
Cash collateral received in support of energy risk management activities	0	0
Accrued interest expense	97	123
Current liabilities - held for sale	0
Other accrued expenses and other current liabilities	328	342
Other accrued expenses and other current liabilities - affiliate	161
Current liabilities - discontinued operations		0
Total current liabilities	879	241
Other Liabilities
Long-term debt and capital leases	6,739	7,461
Nuclear decommissioning reserve	0	0
Nuclear decommissioning trust liability	0	0
Postretirement and other benefit obligations	339	275
Deferred income taxes	(155)	(291)
Derivative instruments	0	0
Out-of-market contracts, net	0	0
Non-current liabilities held-for-sale	0	0
Other non-current liabilities	52	74
Non-current liabilities - discontinued operations		0
Total non-current liabilities	6,975	7,519
Total Liabilities	7,854	7,760
Redeemable noncontrolling interest in subsidiaries	0	0
Total Stockholders' Equity	472	3,748
Total Liabilities and Stockholders' Equity	$ 8,326	$ 11,508

Condensed Consolidating Financial Information - Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows from Operating Activities
Net Loss	$ (1,655)	$ 163	$ (642)	$ (203)	$ (1,055)	$ 393	$ (276)	$ 47	$ (2,337)	$ (891)	$ (6,436)
(Loss)/income from discontinued operations, net of income tax	13	(27)	(741)	(34)	(164)	265	(113)	104	(789)	92	(105)
Net Loss from Continuing Operations	(1,667)	$ 190	$ 99	(170)	(891)	$ 128	$ (163)	(57)	(1,548)	(983)	(6,331)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distributions from unconsolidated affiliates									55	54	37
Depreciation and amortization									1,056	1,172	1,351
Provision for bad debts									68	48	64
Amortization of nuclear fuel									51	49	45
Amortization of financing costs and debt discount/premiums									60	55	47
Adjustment for debt extinguishment									53	142	(10)
Amortization of intangibles and out-of-market contracts									108	167	151
Amortization of unearned equity compensation									35	10	39
Net (gain)/loss on sale of assets and equity method investments									(34)	70	14
Impairment losses									1,788	972	4,916
Changes in derivative instruments									(171)	32	235
Gain on post retirement benefits curtailment									0	0	(21)
Changes in deferred income taxes and liability for uncertain tax benefits									91	(43)	1,326
Changes in collateral deposits in support of risk management activities									(80)	398	(334)
Realized loss on equity method investment									0	0	14
Proceeds from sale of emission allowances									25	34	(24)
Changes in nuclear decommissioning trust liability									11	41	(2)
Cash (used)/provided by changes in other working capital									(143)	(11)	(216)
Cash provided by continuing operations									1,425	2,207	1,287
Cash used by discontinued operations									(38)	(119)	62
Net Cash Provided by Operating Activities									1,387	2,088	1,349
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.									0	0	0
Intercompany dividends									0	0	0
Acquisition of Drop Down Assets, net of cash acquired									0	0	0
Acquisition of businesses, net of cash acquired									(41)	(209)	(31)
Capital expenditures									(1,111)	(976)	(1,029)
Net cash proceeds from notes receivable									17	17	18
Proceeds from renewable energy grants									8	36	82
Proceeds from sale of emission allowances									66		41
Purchases of emission allowances, net of proceeds									66	(1)	41
Investments in nuclear decommissioning trust fund securities									(512)	(551)	(629)
Proceeds from sales of nuclear decommissioning trust fund securities									501	510	631
Proceeds from sale of assets, net									87	73	27
Investments in unconsolidated affiliates									(40)	(23)	(395)
Other									12	35	16
Cash used by continuing operations									(1,013)	(1,089)	(1,269)
Cash used by discontinued operations									(53)	297	(259)
Net Cash Used by Investing Activities									(1,066)	(792)	(1,528)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.									0	0	0
Payments from/(for) intercompany loans									0	0	0
Acquisition of Drop Down Assets, net of cash acquired									0	0	0
Intercompany dividends									0	0	0
Payment of dividends to common and preferred stockholders									(38)	(76)	(201)
Net receipts from settlement of acquired derivatives that include financing elements									2	6	14
Payment for preferred shares										(226)	(437)
Payments for debt extinguishment costs									(42)	(121)	0
Distributions from, net of contributions to, noncontrolling interest in subsidiaries									95	(156)	47
(Payments)/Proceeds from issuance of common stock									(2)	1	1
Proceeds from sale of noncontrolling interests in subsidiaries									0	0	600
Payments from issuance of common stock									2
Proceeds from issuance of long-term debt									2,270	5,527	1,004
Payments of debt issuance and hedging costs									(63)	(89)	(21)
Payments for short and long-term debt									2,348	5,908	1,362
Receivable from affiliate									(125)	0	0
Other									(10)	(13)	(22)
Cash used by continuing operations									(261)	(1,055)	(377)
Cash (used)/provided by discontinued operations									(224)	140	(55)
Net Cash Provided/(Used) by Financing Activities									(485)	(915)	(432)
Effect of exchange rate changes on cash and cash equivalents									(1)	1	10
Change in Cash from discontinued operations									(315)	318	(252)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									150	64	(349)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	1,536				1,386				1,536	1,386	1,322
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				1,386				1,322	1,386	1,322	1,671
Eliminations
Cash Flows from Operating Activities
Net Loss									1,189	(202)	2,848
(Loss)/income from discontinued operations, net of income tax									0	0	0
Net Loss from Continuing Operations									1,189	(202)	2,848
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distributions from unconsolidated affiliates									46	2	(12)
Depreciation and amortization									0	0	0
Provision for bad debts									0	0	0
Amortization of nuclear fuel									0	0	0
Amortization of financing costs and debt discount/premiums									0	0	0
Adjustment for debt extinguishment									0	0	0
Amortization of intangibles and out-of-market contracts									0	0	0
Amortization of unearned equity compensation									0	0	0
Net (gain)/loss on sale of assets and equity method investments									0	0	0
Impairment losses									0	0	0
Changes in derivative instruments									(26)	0	0
Gain on post retirement benefits curtailment											0
Changes in deferred income taxes and liability for uncertain tax benefits									0	0	0
Changes in collateral deposits in support of risk management activities									0	0	0
Realized loss on equity method investment											0
Proceeds from sale of emission allowances									0	0	0
Changes in nuclear decommissioning trust liability									0	0	0
Cash (used)/provided by changes in other working capital									(1,209)	200	(2,836)
Cash provided by continuing operations									0	0	0
Cash used by discontinued operations									0	0	0
Net Cash Provided by Operating Activities									0	0	0
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.									(94)	(81)	(70)
Intercompany dividends									(129)	(12)	(33)
Acquisition of Drop Down Assets, net of cash acquired									249	77	698
Acquisition of businesses, net of cash acquired									0	0	0
Capital expenditures									0	0	0
Net cash proceeds from notes receivable									0	0	0
Proceeds from renewable energy grants									0	0	0
Proceeds from sale of emission allowances									0		0
Purchases of emission allowances, net of proceeds										0
Investments in nuclear decommissioning trust fund securities									0	0	0
Proceeds from sales of nuclear decommissioning trust fund securities									0	0	0
Proceeds from sale of assets, net									0	0	0
Investments in unconsolidated affiliates									0	0	0
Other									0	0	0
Cash used by continuing operations									26	(16)	595
Cash used by discontinued operations									0	0	0
Net Cash Used by Investing Activities									26	(16)	595
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.									94	81	70
Payments from/(for) intercompany loans									0	0	0
Acquisition of Drop Down Assets, net of cash acquired									(249)	(77)	(698)
Intercompany dividends									129	12	33
Payment of dividends to common and preferred stockholders									0	0	0
Net receipts from settlement of acquired derivatives that include financing elements									0	0	0
Payment for preferred shares										0	0
Payments for debt extinguishment costs									0	0
Distributions from, net of contributions to, noncontrolling interest in subsidiaries									0	0	0
(Payments)/Proceeds from issuance of common stock										0	0
Proceeds from sale of noncontrolling interests in subsidiaries											0
Payments from issuance of common stock									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									0	0	0
Receivable from affiliate									0
Other									0	0	0
Cash used by continuing operations									(26)	16	(595)
Cash (used)/provided by discontinued operations									0	0	0
Net Cash Provided/(Used) by Financing Activities									(26)	16	(595)
Effect of exchange rate changes on cash and cash equivalents									0	0	0
Change in Cash from discontinued operations									0	0	0
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									0	0	0
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	0				0				0	0	0
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				0				0	0	0	0
Guarantor Subsidiaries
Cash Flows from Operating Activities
Net Loss									(1,001)	567	(2,449)
(Loss)/income from discontinued operations, net of income tax									0	0	0
Net Loss from Continuing Operations									(1,001)	567	(2,449)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distributions from unconsolidated affiliates									0	(5)	(5)
Depreciation and amortization									405	565	751
Provision for bad debts									54	41	58
Amortization of nuclear fuel									51	49	45
Amortization of financing costs and debt discount/premiums									0	0	0
Adjustment for debt extinguishment									0	0	0
Amortization of intangibles and out-of-market contracts									27	39	52
Amortization of unearned equity compensation									0	0	0
Net (gain)/loss on sale of assets and equity method investments									(18)	0	0
Impairment losses									1,463	378	4,494
Changes in derivative instruments									(100)	(77)	264
Gain on post retirement benefits curtailment											0
Changes in deferred income taxes and liability for uncertain tax benefits									(300)	(1)	(1,092)
Changes in collateral deposits in support of risk management activities									(98)	437	(323)
Realized loss on equity method investment											0
Proceeds from sale of emission allowances									25	34	(24)
Changes in nuclear decommissioning trust liability									11	41	(2)
Cash (used)/provided by changes in other working capital									(363)	(1,815)	(8,656)
Cash provided by continuing operations									156	253	(6,887)
Cash used by discontinued operations									0	0	0
Net Cash Provided by Operating Activities									156	253	(6,887)
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.									0	0	0
Intercompany dividends									0	0	0
Acquisition of Drop Down Assets, net of cash acquired									0	0	0
Acquisition of businesses, net of cash acquired									(14)	0	0
Capital expenditures									(183)	(180)	(316)
Net cash proceeds from notes receivable									0	0	0
Proceeds from renewable energy grants									8	0	0
Proceeds from sale of emission allowances									66		41
Purchases of emission allowances, net of proceeds										(1)
Investments in nuclear decommissioning trust fund securities									(512)		(629)
Proceeds from sales of nuclear decommissioning trust fund securities									501	510	631
Proceeds from sale of assets, net									33	0	0
Investments in unconsolidated affiliates									0	3	1
Other									18	27	0
Cash used by continuing operations									(83)	(192)	(272)
Cash used by discontinued operations									0	0	0
Net Cash Used by Investing Activities									(83)	(192)	(272)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.									0	0	0
Payments from/(for) intercompany loans									(45)	(52)	7,183
Acquisition of Drop Down Assets, net of cash acquired									0	0	0
Intercompany dividends									0	(52)	0
Payment of dividends to common and preferred stockholders									0	0	0
Net receipts from settlement of acquired derivatives that include financing elements									0	0	0
Payment for preferred shares										0	0
Payments for debt extinguishment costs									0	0
Distributions from, net of contributions to, noncontrolling interest in subsidiaries									0	0	0
(Payments)/Proceeds from issuance of common stock										0	0
Proceeds from sale of noncontrolling interests in subsidiaries											0
Payments from issuance of common stock									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									0	1	0
Receivable from affiliate									0
Other									0	(3)	0
Cash used by continuing operations									(45)	(108)	7,183
Cash (used)/provided by discontinued operations									0	0	0
Net Cash Provided/(Used) by Financing Activities									(45)	(108)	7,183
Effect of exchange rate changes on cash and cash equivalents									0	0	0
Change in Cash from discontinued operations									0	0	0
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									28	(47)	24
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	41				13				41	13	60
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				13				60	13	60	36
Non-Guarantor Subsidiaries
Cash Flows from Operating Activities
Net Loss									(356)	(538)	(484)
(Loss)/income from discontinued operations, net of income tax									(160)	81	(115)
Net Loss from Continuing Operations									(196)	(619)	(369)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distributions from unconsolidated affiliates									5	52	54
Depreciation and amortization									619	581	580
Provision for bad debts									2	7	3
Amortization of nuclear fuel									0	0	0
Amortization of financing costs and debt discount/premiums									42	34	21
Adjustment for debt extinguishment									4	4	9
Amortization of intangibles and out-of-market contracts									81	128	99
Amortization of unearned equity compensation									0	0	(2)
Net (gain)/loss on sale of assets and equity method investments									(16)	0	0
Impairment losses									321	578	391
Changes in derivative instruments									(69)	145	(29)
Gain on post retirement benefits curtailment											(21)
Changes in deferred income taxes and liability for uncertain tax benefits									69	18	(237)
Changes in collateral deposits in support of risk management activities									18	(39)	(11)
Realized loss on equity method investment											0
Proceeds from sale of emission allowances									0	0	0
Changes in nuclear decommissioning trust liability									0	0	0
Cash (used)/provided by changes in other working capital									(164)	417	(907)
Cash provided by continuing operations									716	1,306	(419)
Cash used by discontinued operations									(38)	(119)	62
Net Cash Provided by Operating Activities									678	1,187	(357)
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.									0	0	0
Intercompany dividends									0	0	0
Acquisition of Drop Down Assets, net of cash acquired									(249)	(77)	(698)
Acquisition of businesses, net of cash acquired									(27)	(209)	(31)
Capital expenditures									(906)	(748)	(654)
Net cash proceeds from notes receivable									17	17	18
Proceeds from renewable energy grants									0	36	82
Proceeds from sale of emission allowances									0		0
Purchases of emission allowances, net of proceeds										0
Investments in nuclear decommissioning trust fund securities									0	0	0
Proceeds from sales of nuclear decommissioning trust fund securities									0	0	0
Proceeds from sale of assets, net									54	56	1
Investments in unconsolidated affiliates									(40)	(26)	(357)
Other									(6)	0	16
Cash used by continuing operations									(1,157)	(951)	(1,623)
Cash used by discontinued operations									(53)	297	(259)
Net Cash Used by Investing Activities									(1,210)	(654)	(1,882)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.									(94)	(81)	(70)
Payments from/(for) intercompany loans									13	(49)	1,258
Acquisition of Drop Down Assets, net of cash acquired									0	0	0
Intercompany dividends									(129)	40	(33)
Payment of dividends to common and preferred stockholders									0	0	0
Net receipts from settlement of acquired derivatives that include financing elements									2	6	14
Payment for preferred shares										0	0
Payments for debt extinguishment costs									0	0
Distributions from, net of contributions to, noncontrolling interest in subsidiaries									95	(156)	47
(Payments)/Proceeds from issuance of common stock										0	0
Proceeds from sale of noncontrolling interests in subsidiaries											600
Payments from issuance of common stock									0
Proceeds from issuance of long-term debt									1,186	1,387	953
Payments of debt issuance and hedging costs									(47)	(29)	(21)
Payments for short and long-term debt									647	983	1,116
Receivable from affiliate									(125)
Other									(10)	(10)	(22)
Cash used by continuing operations									244	125	1,610
Cash (used)/provided by discontinued operations									(224)	140	(55)
Net Cash Provided/(Used) by Financing Activities									20	265	1,555
Effect of exchange rate changes on cash and cash equivalents									(1)	1	10
Change in Cash from discontinued operations									(315)	318	(252)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									(198)	481	(422)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	852				1,050				852	1,050	569
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				1,050				569	1,050	569	991
NRG Energy, Inc. (Note Issuer)
Cash Flows from Operating Activities
Net Loss									(2,169)	(718)	(6,351)
(Loss)/income from discontinued operations, net of income tax									(629)	11	10
Net Loss from Continuing Operations									(1,540)	(729)	(6,361)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distributions from unconsolidated affiliates									4	5	0
Depreciation and amortization									32	26	20
Provision for bad debts									12	0	3
Amortization of nuclear fuel									0	0	0
Amortization of financing costs and debt discount/premiums									18	21	26
Adjustment for debt extinguishment									49	138	(19)
Amortization of intangibles and out-of-market contracts									0	0	0
Amortization of unearned equity compensation									35	10	41
Net (gain)/loss on sale of assets and equity method investments									0	70	14
Impairment losses									4	16	31
Changes in derivative instruments									24	(36)	0
Gain on post retirement benefits curtailment											0
Changes in deferred income taxes and liability for uncertain tax benefits									322	(60)	2,655
Changes in collateral deposits in support of risk management activities									0	0	0
Realized loss on equity method investment											14
Proceeds from sale of emission allowances									0	0	0
Changes in nuclear decommissioning trust liability									0	0	0
Cash (used)/provided by changes in other working capital									1,593	1,187	12,183
Cash provided by continuing operations									553	648	8,593
Cash used by discontinued operations									0	0	0
Net Cash Provided by Operating Activities									553	648	8,593
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.									94	81	70
Intercompany dividends									129	12	33
Acquisition of Drop Down Assets, net of cash acquired									0	0	0
Acquisition of businesses, net of cash acquired									0	0	0
Capital expenditures									(22)	(48)	(59)
Net cash proceeds from notes receivable									0	0	0
Proceeds from renewable energy grants									0	0	0
Proceeds from sale of emission allowances									0		0
Purchases of emission allowances, net of proceeds										0
Investments in nuclear decommissioning trust fund securities									0	0	0
Proceeds from sales of nuclear decommissioning trust fund securities									0	0	0
Proceeds from sale of assets, net									0	17	26
Investments in unconsolidated affiliates									0	0	(39)
Other									0	8	0
Cash used by continuing operations									201	70	31
Cash used by discontinued operations									0	0	0
Net Cash Used by Investing Activities									201	70	31
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.									0	0	0
Payments from/(for) intercompany loans									32	101	(8,441)
Acquisition of Drop Down Assets, net of cash acquired									249	77	698
Intercompany dividends									0	0	0
Payment of dividends to common and preferred stockholders									(38)	(76)	(201)
Net receipts from settlement of acquired derivatives that include financing elements									0	0	0
Payment for preferred shares										(226)	(437)
Payments for debt extinguishment costs									(42)	(121)
Distributions from, net of contributions to, noncontrolling interest in subsidiaries									0	0	0
(Payments)/Proceeds from issuance of common stock										1	1
Proceeds from sale of noncontrolling interests in subsidiaries											0
Payments from issuance of common stock									2
Proceeds from issuance of long-term debt									1,084	4,140	51
Payments of debt issuance and hedging costs									(16)	(60)	0
Payments for short and long-term debt									1,701	4,924	246
Receivable from affiliate									0
Other									0	0	0
Cash used by continuing operations									(434)	(1,088)	(8,575)
Cash (used)/provided by discontinued operations									0	0	0
Net Cash Provided/(Used) by Financing Activities									(434)	(1,088)	(8,575)
Effect of exchange rate changes on cash and cash equivalents									0	0	0
Change in Cash from discontinued operations									0	0	0
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									320	(370)	49
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$ 643				$ 323				643	323	693
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				$ 323				$ 693	$ 323	$ 693	$ 644

VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	$ 10
Balance at End of Period		$ 10
Allowance for doubtful accounts, deducted from accounts receivable
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	29	21	$ 21
Charged to Costs and Expenses	56	47	62
Charged to Other Accounts	0	0	0
Deductions	(57)	(39)	(62)
Balance at End of Period	28	29	21
Income tax valuation allowance, deducted from deferred tax assets
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	4,116	3,575	265
Charged to Costs and Expenses	(151)	306	3,039
Charged to Other Accounts	(15)	235	271
Deductions	(2,087)	0	0
Balance at End of Period	1,863	4,116	3,575
Income tax valuation allowance, deducted from deferred tax assets \| Discontinued Operations
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	$ 2,087	2,194
Balance at End of Period		$ 2,087	$ 2,194