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Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Jan. 31, 2019	Jun. 30, 2018
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, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filer	No
Entity Current Reporting Status	Yes
Entity Filer category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Public Float			$ 7,964,294,696
Entity Common Stock, Shares Outstanding		280,997,550
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues
Total operating revenues	$ 9,478	$ 9,074	$ 8,915
Operating Costs and Expenses
Cost of operations	7,108	6,886	6,676
Depreciation and amortization	421	596	756
Impairment losses	99	1,534	483
Selling, general and administrative	799	836	1,032
Reorganization costs	90	44	0
Development costs	11	22	48
Total operating costs and expenses	8,528	9,918	8,995
Other income - affiliate	0	87	193
Gain on sale of assets	32	16	(80)
Operating Income/(Loss)	982	(741)	33
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	9	(14)	(18)
Impairment losses on investments	(15)	(79)	(268)
Other income, net	18	51	47
Loss on debt extinguishment, net	(44)	(49)	(142)
Interest expense	(483)	(557)	(583)
Total other expense	(515)	(648)	(964)
Income/(Loss) from Continuing Operations Before Income Taxes	467	(1,389)	(931)
Income tax expense/(benefit)	7	(44)	25
Net Income/(Loss) from Continuing Operations	460	(1,345)	(956)
(Loss)/income from discontinued operations, net of income tax	(192)	(992)	65
Net Income/(Loss)	268	(2,337)	(891)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	(184)	(117)
Net Income/(Loss) Attributable to NRG Energy, Inc.	268	(2,153)	(774)
Dividends for preferred shares	0	0	5
Gain on redemption of preferred shares	0	0	(78)
Income/(Loss) Available for Common Stockholders	$ 268	$ (2,153)	$ (701)
Earnings/(Loss) Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic (in shares)	304,000,000	317,000,000	316,000,000
Income/(loss) from continuing operations per weighted average common share — basic (in usd per share)	$ 1.51	$ (3.66)	$ (2.42)
(Loss)/Income from discontinued operations per weighted average common share — basic (in usd per share)	(0.63)	(3.13)	0.20
Net Income/(Loss) per Weighted Average Common Share — Basic (in	$ 0.88	$ (6.79)	$ (2.22)
Weighted average number of common shares outstanding — diluted (in shares)	308,000,000	317,000,000	316,000,000
Income/(loss) from continuing operations per weighted average common share — diluted (in usd per share)	$ 1.49	$ (3.66)	$ (2.42)
(Loss)/income from discontinued operations per weighted average common share — diluted (In usd per share)	(0.62)	(3.13)	0.20
Net Income/(Loss)/income per weighted average common share — diluted (in usd per share)	0.87	(6.79)	(2.22)
Dividends Per Common Share (in usd per share)	$ 0.12	$ 0.12	$ 0.24

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net Income/(Loss)	$ 268	$ (2,337)	$ (891)
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain on derivatives, net of income tax expense of $0, $1, and $1	23	13	35
Foreign currency translation adjustments, net of income tax benefit of $0, $(2), and $0	(11)	12	(1)
Available-for-sale securities, net of income tax expense of $0, $10, and $0	1	(8)	1
Defined benefit plan, net of income tax (benefit)/expense of $0, $(21), and $0	(35)	46	3
Other comprehensive (loss)/income	(22)	63	38
Comprehensive Income/(Loss)	246	(2,274)	(853)
Less: Comprehensive income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests	14	(179)	(117)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	232	(2,095)	(736)
Dividends for preferred shares	0	0	5
Gain on redemption of preferred shares	0	0	(78)
Comprehensive Income/(Loss) Available for Common Stockholders	$ 232	$ (2,095)	$ (663)

Consolidated Statements of Comprehensive (Loss)/Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Unrealized gain/(loss) on derivatives, income tax expense	$ 0	$ 1	$ 1
Foreign currency translation adjustments, income tax benefit	0	(2)	0
Available-for-sale securities, income tax expense	0	10	0
Defined benefit plan, income tax (benefit)/expense	$ 0	$ (21)	$ 0

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 563	$ 770
Funds deposited by counterparties	33	37
Restricted cash	17	279
Accounts receivable - trade	1,019	900
Inventory	412	453
Derivative instruments	764	624
Cash collateral posted in support of energy risk management activities	287	171
Accounts receivable - affiliate	5	180
Prepayments and other current assets	302	163
Current assets - held-for-sale	1	116
Current assets - discontinued operations	197	744
Total current assets	3,600	4,437
Property, plant and equipment, net	3,048	5,974
Other Assets
Equity investments in affiliates	412	182
Goodwill	573	539
Intangible assets, net	591	507
Nuclear decommissioning trust fund	663	692
Derivative instruments	317	159
Other non-current assets	289	310
Non-current assets - held-for-sale	77	43
Non-current assets - discontinued operations	1,012	10,506
Total other assets	3,980	12,944
Total Assets	10,628	23,355
Current Liabilities
Current portion of long-term debt and capital leases	72	204
Accounts payable	862	684
Accounts payable - affiliate	1	57
Derivative instruments	673	537
Cash collateral received in support of energy risk management activities	33	37
Accrued expenses and other current liabilities	680	756
Accrued expenses and other current liabilities - affiliate	0	161
Current liabilities - held for sale	5	72
Current liabilities - discontinued operations	72	846
Total current liabilities	2,398	3,354
Other Liabilities
Long-term debt and capital leases	6,449	9,180
Nuclear decommissioning reserve	282	269
Nuclear decommissioning trust liability	371	415
Postretirement and other benefit obligations	435	458
Derivative instruments	304	143
Deferred income taxes	65	21
Out-of-market contracts, net	121	129
Other non-current liabilities	718	534
Non-current liabilities - held-for-sale	65	8
Non-current liabilities - discontinued operations	635	6,798
Total non-current liabilities	9,445	17,955
Total Liabilities	11,843	21,309
Redeemable noncontrolling interest in subsidiaries	19	78
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 420,288,886 and 418,323,134 shares issued; and 283,650,039 and 316,743,089 shares outstanding at December 31, 2018 and 2017	4	4
Additional paid-in capital	8,510	8,376
Accumulated deficit	(6,022)	(6,268)
Treasury stock, at cost; 136,638,847 and 101,580,045 shares at December 31, 2018 and 2017	(3,632)	(2,386)
Accumulated other comprehensive loss	(94)	(72)
Noncontrolling interest	0	2,314
Total Stockholders' Equity	(1,234)	1,968
Total Liabilities and Stockholders' Equity	10,628	23,355
Continuing Operations
Other Assets
Deferred income taxes	$ 46	$ 6

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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)	420,288,886	418,323,134
Common stock, shares outstanding (in shares)	283,650,039	316,743,089
Treasury stock, shares (in shares)	136,638,847	101,580,045

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities
Net Income/(Loss)	$ 268	$ (2,337)	$ (891)
(Loss)/income from discontinued operations, net of income tax	(192)	(992)	65
Net Income/(Loss) from Continuing Operations	460	(1,345)	(956)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	46	102	67
Depreciation, amortization and accretion	459	596	772
Provision for bad debts	85	68	45
Amortization of nuclear fuel	48	51	49
Amortization of financing costs and debt discount/premiums	29	29	33
Adjustment for debt extinguishment	44	49	142
Amortization of intangibles and out-of-market contracts	45	54	68
Amortization of unearned equity compensation	25	35	10
Net (gain)/loss on sale of assets and equity/cost method investments	(49)	(9)	139
Impairment losses	114	1,614	751
Changes in derivative instruments	37	(170)	16
Changes in deferred income taxes and liability for uncertain tax benefits	5	13	(12)
Changes in collateral deposits in support of risk management activities	(105)	(80)	396
Changes in nuclear decommissioning trust liability	60	11	41
GenOn settlement, net of insurance proceeds	(63)	0	0
Net loss on deconsolidation of Agua Caliente and Ivanpah projects	13	0	0
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects:
Accounts receivable - trade	(83)	(83)	24
Inventory	31	143	60
Prepayments and other current assets	(41)	(187)	(120)
Accounts payable	113	44	(59)
Accrued expenses and other current liabilities	(166)	(88)	(61)
Other assets and liabilities	(104)	9	32
Cash provided/(used) by continuing operations	1,003	856	1,437
Cash provided by discontinued operations	374	754	471
Net Cash Provided by Operating Activities	1,377	1,610	1,908
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(243)	(14)	0
Capital expenditures	(388)	(254)	(544)
Proceeds from renewable energy grants	0	8	36
Net proceeds from sale/(purchases) of emission allowances	19	66	(1)
Investments in nuclear decommissioning trust fund securities	(572)	(512)	(551)
Proceeds from sales of nuclear decommissioning trust fund securities	513	501	510
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	1,564	430	241
Deconsolidation of Agua Caliente and Ivanpah projects	(268)	0	0
Changes in investments in unconsolidated affiliates	(39)	(57)	(33)
Net (contributions to)/distributions from discontinued operations	(60)	150	(58)
Other	(6)	22	31
Cash provided/(used) by continuing operations	520	340	(369)
Cash used by discontinued operations	(725)	(979)	(388)
Net Cash Used by Investing Activities	(205)	(639)	(757)
Cash Flows from Financing Activities
Payments of dividends to preferred and common stockholders	(37)	(38)	(76)
Payments for treasury stock	(1,250)	0	0
Payments for preferred shares	0	0	(226)
Payments for debt extinguishment costs	(32)	(42)	(121)
Net distributions to noncontrolling interest from subsidiaries	(16)	(30)	(27)
Proceeds/(payments) from issuance of common stock	21	(2)	1
Proceeds from issuance of long-term debt	1,100	1,178	4,412
Payments of debt issuance costs	(19)	(18)	(61)
Payments for short and long-term debt	(1,734)	(1,884)	(5,146)
Receivable from affiliate	(26)	(125)	0
Other	(4)	(8)	(7)
Cash used by continuing operations	(1,997)	(969)	(1,251)
Cash provided/(used) by discontinued operations	471	(169)	483
Net Cash (Used)/Provided by Financing Activities	(1,526)	(1,138)	(768)
Effect of exchange rate changes on cash and cash equivalents	1	(1)	1
Change in Cash from discontinued operations	120	(394)	566
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(473)	226	(182)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,086	860	1,042
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$ 613	$ 1,086	$ 860

CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY - USD ($) $ in Millions	Total	NRG Yield, Inc.	Common Stock	Additional Paid-In Capital	Additional Paid-In Capital NRG Yield, Inc.	Accumulated Deficit	Treasury Stock	Accumulated Other Comprehensive Loss	Noncon- trolling Interest	Noncon- trolling Interest NRG Yield, Inc.
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
Sale of assets to NRG Yield, Inc.		$ 43			$ 59					$ (16)
ESPP share purchases	6			(2)		(6)	14
Equity-based compensation	6			5		1
Common stock dividends	(74)					(74)
Dividend for preferred shares	(5)					(5)
Gain on redemption of preferred shares	78					78
Distributions to noncontrolling interest and dividends paid	(158)	(92)							(158)	(92)
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
Other comprehensive income	51							51
Sale of assets to NRG Yield, Inc.		(5)			(25)					20
ESPP share purchases	6			(3)		(4)	13
Equity-based compensation	29			29
Common stock dividends	(38)					(38)
Gain on redemption of preferred shares	0
Distributions to noncontrolling interest and dividends paid	(65)	(108)							(65)	(108)
Contributions from noncontrolling interests	160								160
Early adoption of new accounting standards	(257)			17		(286)		12
Balance at Dec. 31, 2017	1,968		4	8,376		(6,268)	(2,386)	(72)	2,314
Increase (Decrease) in Stockholders' Equity
Net loss	294					268			26
Other comprehensive income (loss)	(22)							(22)
Sale of assets to NRG Yield, Inc.		16			$ 8					8
ESPP share purchases	2			(2)			4
Share repurchases	(1,250)						(1,250)
Equity-based compensation	27			27
Common stock dividends	(37)					(37)
Gain on redemption of preferred shares	0
Distributions to noncontrolling interest and dividends paid	(43)	$ (61)							(43)	$ (61)
Contributions from noncontrolling interests	304								304
Sale of NRG Yield and other business	(2,548)								(2,548)
Equity component of convertible senior notes	101			101
Balance at Dec. 31, 2018	(1,234)		$ 4	$ 8,510		(6,022)	$ (3,632)	$ (94)	$ 0
Increase (Decrease) in Stockholders' Equity
Adoption of new accounting standards	$ 15					$ 15

Nature of Business

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Business

General

NRG Energy, Inc., or NRG or the Company, is an energy company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers 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. NRG is perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving to a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names "NRG" and "Reliant" and other brand names owned by NRG supported by approximately 23,000^(a) MW of generation as of December 31, 2018.

Retail is a consumer facing business that includes residential and small commercial (Mass Market) consumers and the Company's Business Solutions group, which includes demand response, commodity sales, energy efficiency and energy management solutions. 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.

The Company's Generation business includes plant operations, commercial operations, EPC, asset management, energy services and other critical related functions. In addition to the traditional functions from NRG's wholesale power generation business, Generation also includes NRG's retained renewable generation business.

Discontinued Operations

On December 31, 2018, as described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company concluded that the sale of its South Central Portfolio to Cleco, excluding the Cottonwood facility, met held-for-sale criteria and should be presented as a discontinued operation, as the sale represented a strategic shift in the business in which NRG operates. The financial information for all historical periods has been recast to reflect the presentation of these entities as discontinued operations.

On August 31, 2018, as described in Note 3, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc. and its Renewables Platform for financial reporting purposes. The financial information for all historical periods has been recast to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations. As a result of the sale of NRG Yield, the Company no longer controls the Agua Caliente project. Due to this change in control, the Company has deconsolidated the Agua Caliente project from its financial results and has accounted for the project as an equity method investment.

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 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. GenOn's plan of reorganization was confirmed on December 14, 2018.


(a)	excluding discontinued operations and held for sale

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

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 U.S. GAAP for SEC registrants.

The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated.

Net Income/(Loss) attributable to NRG Energy, Inc.

The following table reflects the net income/(loss) attributable to NRG Energy, Inc. after removing the net loss attributable to the noncontrolling interest and redeemable noncontrolling interest:



	Year Ended December 31,
	2018			2017			2016
	(In millions)
Income/(loss) from continuing operations, net of income tax	$	465		$	(977	)	$	(733	)
Loss from discontinued operations, net of income tax	(197		)	(1,176		)	(41		)
Net income/(loss) attributable to NRG Energy, Inc. stockholders	$	268		$	(2,153	)	(774		)

Segment Reporting

The Company's businesses are segregated into the Generation, Retail and corporate segments. Generation includes all power plant activities, domestic and international, as well as renewables. Retail includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products.

As described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company has determined that the South Central Portfolio, NRG Yield Inc. and its Renewables Platform, Carlsbad, and GenOn all qualified for treatment as a discontinued operation. The financial information for all historical periods has been recast to reflect the presentation of discontinued operations within the corporate segment.

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 sheets that sum to the total of the same such amounts shown in the statements of cash flows.



	Year Ended December 31,
	2018		2017		2016
	(In millions)
Cash and cash equivalents	$	563	$	770	$	591
Funds deposited by counterparties	33		37		2
Restricted cash	17		279		267
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$	613	$	1,086	$	860

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

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, 2018 and 2017, the allowance for doubtful accounts was $32 million and $28 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. 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 9, 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, 2018, 2017, and 2016, was $7 million, $20 million, and $29 million, respectively.

Debt Issuance Costs

Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt.

Intangible Assets

Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, power purchase agreements, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. 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, 2018 and 2017, the Company had accumulated amortization related to its intangible assets of $1.2 billion and $1.6 billion, respectively.

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 refer to Note 10, Goodwill and Other Intangibles.

Income Taxes

The Company accounts for income taxes using the liability method in accordance with ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

The Company has two categories of income tax expense or benefit — current and deferred, as follows:


•	Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and


•	Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income

The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. The Company believes it is more-likely-than-not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in its estimate of future taxable income, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized.

The Company reduces its current income tax expense in the consolidated statement of operations for any investment tax credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently amortized to earnings on a straight-line basis over the useful life of each underlying property.

The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.

In accordance with ASC 805 and as discussed further in Note 18, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.

Revenue Recognition

Revenue from Contracts with Customers

On January 1, 2018, the Company adopted the guidance in ASC 606 using the modified retrospective method applied to contracts that were not completed as of the adoption date. The Company recognized the cumulative effect of initially applying the new standard as a credit to the opening balance of accumulated deficit, resulting in a decrease of approximately $15 million. The adjustment primarily related to costs incurred to obtain a contract with customers and customer incentives. Following the adoption of the new standard, the Company’s revenue recognition of its contracts with customers remains materially consistent with its historical practice. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The Company's policies with respect to its various revenue streams are detailed below. In general, the Company applies the invoicing practical expedient to recognize revenue for the revenue streams detailed below, except in circumstances where the invoiced amount does not represent the value transferred to the customer.

Retail Revenues

Gross revenues for energy sales and services to retail customers are recognized as the Company transfers the promised goods and services to the customer. For the majority of its electricity contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligation in a contract for which the timing of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration and are recognized over the term of the contract.

Energy sales and services that have been delivered but not billed by period end are estimated. 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.

As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.

Energy Revenue

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 over time, using the output method for measuring progress of satisfaction of performance obligations. 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. The Company applies the invoicing practical expedient, where applicable, in recognizing energy revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. 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 Revenue

Capacity revenues consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation and demand response capacity available in order to satisfy system integrity and reliability requirements. Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance obligations. The Company applies the invoicing practical expedient, where applicable, in recognizing capacity revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date.

Capacity revenue contracts mainly consist of:

Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet. In addition, MISO has an annual auction, known as the Planning Resource Auction, or PRA. As of December 31, 2018, estimated future revenues for cleared auction MWs in the various capacity auctions are $618 million, $481 million, $532 million, and $244 million for fiscal years 2019, 2020, 2021 and 2022, respectively.

Resource adequacy and bilateral contracts — In California, there is a resource adequacy requirement that is primarily satisfied through bilateral contracts. Such bilateral contracts are typically short-term resource adequacy contracts. When bilateral contracting does not satisfy the resource adequacy need, such shortfalls can be addressed through procurement tools administered by the CAISO, including the capacity procurement mechanism or reliability must-run contracts. Demand payments from the current long-term contracts are tied to summer peak demand and provide a mechanism for recovering a portion of the costs associated with new or changed environmental laws or regulations. In Texas and New York, capacity and contracted revenues are through bilateral contracts with third parties of our Retail segment.

Renewable Energy Credits

Renewable energy credits are usually sold through long-term contracts. Revenue from the sale of self-generated RECs is recognized when related energy is generated and simultaneously delivered even in cases where there is a certification lag as it has been deemed to be perfunctory.

In a bundled contract to sell energy, capacity and/or self-generated RECs, all performance obligations are deemed to be delivered at the same time and hence, timing of recognition of revenue for all performance obligations is the same and occurs over time. In such cases, it is often unnecessary to allocate transaction price to multiple performance obligations.

Sale of Emission Allowances

The Company records its inventory of emission allowances as part of intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of expected 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.

Disaggregated Revenues

The following table represents the Company’s disaggregation of revenue from contracts with customers for the year ended December 31, 2018, along with the reportable segment for each category:



	For the Year Ended December 31, 2018
				Generation
(In millions)	Retail			Texas			East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue^(a)	$	—		$	1,585		$	1,092		$	2,677		$	(1,129	)	$	1,548
Capacity revenue^(a)	—			1			669			670			—			670
Retail revenue
Mass customers	5,618			—			—			—			(5		)	5,613
Business Solutions customers	1,492			—			—			—			—			1,492
Total retail revenue	7,110			—			—			—			(5		)	7,105
Mark-to-market for economic hedging activities^(b)	(7		)	(174		)	(28		)	(202		)	79			(130		)
Other revenue^(a)(c)	—			84			203			287			(2		)	285
Total operating revenue	7,103			1,496			1,936			3,432			(1,057		)	9,478
Less: Lease revenue	13			—			8			8			—			21
Less: Derivative revenue	(7		)	2,160			193			2,353			(1,037		)	1,309
Total revenue from contracts with customers	$	7,097		$	(664	)	$	1,735		$	1,071		$	(20	)	$	8,148
(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
	Retail			Texas			East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	2,332		$	69		$	2,401		$	(1,117	)	$	1,284
Capacity revenue	—			—			138			138			—			138
Other revenue	—			2			14			16			—			16

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

(c) Included in other revenue is lease revenue of $17 million and $5 million for Retail and East/West/Other, respectively

Contract Amortization

Assets and liabilities recognized 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.

Lease Revenue

Certain of the Company’s revenues are obtained through leases of rooftop residential solar systems, which are accounted for as operating leases in accordance with ASC 840, Leases. Pursuant to the lease agreements, the customers’ monthly payments are pre-determined fixed monthly amounts and may include an annual fixed percentage escalation to reflect the impact of utility rate increases over the lease term, which is 20 years. The Company records operating lease revenue on a straight-line basis over the life of the lease term. Certain customers made initial down payments that are being amortized over the life of the lease. The difference between the payments received and the revenue recognized is recorded as deferred revenue.

Contract Balances

The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31, 2018:




	(In millions)
Deferred customer acquisition costs	$	111

Accounts receivable, net - Contracts with customers	1,002
Accounts receivable, net - Derivative instruments	20
Total accounts receivable, net	$	1,022

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	392
Deferred revenues	$	67

The Company's customer acquisition costs consist of broker fees, commission payments and other costs that represent incremental costs of obtaining the contract with customers for which the Company expects to recover. The Company amortizes these amounts over the estimated life of the customer contract. As a practical expedient, the Company expenses the incremental costs of obtaining a contract if the amortization period of the asset would have been one year or less.

When the Company receives consideration from the customer that is in excess of the amount due, such consideration is reclassified to deferred revenue, which represents a contract liability. Generally, the Company will recognize revenue from contract liabilities in the next period as the Company satisfies its performance obligations.

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, 2018, 2017, and 2016 was $104 million, $253 million, and $272 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, 2018, 2017, and 2016, the Company's revenues and cost of operations included gross receipts taxes of $99 million, $92 million, and $101 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 $105 million, $107 million, and $90 million as of December 31, 2018, 2017, and 2016, 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, 2018, 2017, and 2016, amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2018, 2017, and 2016 were $(13) million, $(2) million and $(11) 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 12 , 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 assist in determining 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. 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, 2018, 2017, and 2016.



	(In millions)
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
Distributions to redeemable noncontrolling interest	(3		)
Contributions from redeemable noncontrolling interest	26
Non-cash adjustments to redeemable noncontrolling interest	(8		)
Net income attributable to redeemable noncontrolling interest - continuing operations	1
Net loss attributable to redeemable noncontrolling interest - discontinued operations	(27		)
Sale of NRG Yield and the Renewables Platform^(a)	(48		)
Balance as of December 31, 2018	$	19

(a) See Note 3, Acquisitions, Discontinued Operations and Dispositions, for further information regarding the sale of NRG Yield and its Renewables Platform

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.

As described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company entered into an agreement to leaseback the Cottonwood facility upon the close of the South Central Portfolio transaction. The lease will be accounted for as an operating lease and accordingly, a right of use asset and lease liability will be set up on the lease commencement date which will be amortized through the end of the lease.

Marketing and Advertising Costs

The Company expenses its marketing and advertising costs as incurred and which are included within selling, general and administrative expenses. 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, 2018, 2017, and 2016 were $73 million, $66 million, and $79 million, respectively.

Reorganization Costs

Reorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily reflect severance and contract modifications. As of December 31, 2018 and December 31, 2017, $90 million and $44 million were 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 2018

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. Previous 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 did not have a material impact on the Company's results of operations, cash flows, and statement of financial position.

ASU 2016-01 - In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) be generally measured at fair value with changes in fair value recognized in net income. Further, the amendments require that financial assets and financial liabilities be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset. The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company adopted the amendments of ASU No. 2016-01 effective January 1, 2018. In connection with the adoption of the standard, the Company has applied the guidance on a modified retrospective basis, which resulted in no material adjustments recorded to the consolidated results of operations, cash flows, and statement of financial position.

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, did 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 has been disclosing since the date of adoption.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2018-17 - In October 2018, the FASB issued ASU No. 2018-17, Consolidations (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities, in response to stakeholders’ observations that Topic 810, Consolidations, could be improved thereby improving general purpose financial reporting. Specifically, ASC 2018-17 requires application of the variable interest entity (VIE) guidance to private companies under common control and consideration of indirect interest held through related parties under common control for determining whether fees paid to decision makers and service providers are variable interests. The amendments are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. All entities are required to apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. The Company is evaluating the impact of adopting this guidance on the consolidated financial statements and disclosures.

ASU 2018-13 - In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirement for Fair value Measurement), or ASU No. 2018-13. The guidance in ASU No. 2018-13 eliminates such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. The amendments in ASU No. 2018-13 add new disclosure requirements for Level 3 measurements. ASU No. 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted for any eliminated or modified disclosures. Certain disclosures in ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. As the amendment contemplates changes in disclosures only, it will have no material impact on the Company's results of operations, cash flows, or 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 adopted the standard and its subsequent corresponding updates effective January 1, 2019 under the modified retrospective approach by applying the provisions of the new leases guidance at the effective date without adjusting the comparative periods presented. The Company has assessed its leasing arrangements and evaluated the impact of applying practical expedients and accounting policy elections. The Company implemented lease accounting software to meet the reporting requirements of the standard and identified changes to its business processes and controls to support recognition and disclosure under the new standard. Management estimates operating lease liabilities will increase between $380 million and $420 million and right-of-use assets between $300 million and $340 million will be established upon adoption, before considering deferred taxes. Management does not believe the adoption of Topic 842 will have a material impact on the statements of operations or cash flows.

Acquisitions, Discontinued Operations and Dispositions Acquisitions, Discontinued Operations and Dispositions

12 Months Ended

Dec. 31, 2018

Discontinued Operations and Disposal Groups [Abstract]

Acquisitions, Discontinued Operations and Dispositions

Acquisitions

XOOM Energy Acquisition — On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada, for approximately $213 million in cash. The acquisition increased NRG's retail portfolio by approximately 300,000 customers. The purchase price was allocated as follows:



	(In millions)
Net current and non-current working capital	$	46
Other intangible assets	133
Goodwill	34
XOOM Purchase Price	$	213

Small Book Acquisitions — Through the end of December 2018, the Company has agreed to acquire several books of customers totaling approximately 115,000 customers, along with brand names, for $44 million, the majority of which was allocated to acquired intangibles.

Discontinued Operations

Sale of South Central Portfolio

On February 4, 2019, the Company completed the sale of its South Central Portfolio to Cleco. The Company concluded that the divested business met the criteria for discontinued operations, as the disposition represents a strategic shift in the business in which NRG operates and held-for-sale criteria as of December 31, 2018. As such, all prior period results for the operations of the South Central Portfolio have been reclassified as discontinued operations. In connection with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested business.

The South Central Portfolio includes the 1,263 MW Cottonwood natural gas generating facility. Upon the closing of the sale of the South Central Portfolio, NRG entered into a lease agreement with Cleco to leaseback the Cottonwood facility through 2025. Due to its continuing involvement with the Cottonwood facility, NRG will not use held-for-sale or discontinued operations treatment in accounting for historical and ongoing activity with Cottonwood.

Summarized results of South Central discontinued operations were as follows:



	Year Ended December 31,
(In millions)	2018			2017			2016
Operating revenues	$	410		$	422		$	467
Operating costs and expenses	(346		)	(335		)	(395		)
Other income	2			—			—
Gain from discontinued operations, net of tax	$	66		$	87		$	72

The following table summarizes the major classes of assets and liabilities classified as discontinued operations of South Central as follows:



(In millions)	December 31, 2018		December 31, 2017
Cash and cash equivalents	$	89	$	(3	)
Accounts receivable, net	49		61
Inventory	35		33
Other current assets	5		—
Current assets - discontinued operations	178		91
Property, plant and equipment, net	408		461
Other non-current assets	1		1
Non-current assets - discontinued operations	409		462
Accounts payable	19		28
Other current liabilities	5		6
Current liabilities - discontinued operations	24		34
Out-of-market contracts, net	50		66
Other non-current liabilities	11		10
Non-current liabilities - discontinued operations	$	61	$	76

Sale of Ownership in NRG Yield, Inc. and its Renewables Platform

On August 31, 2018, the Company completed the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform to GIP for total cash consideration of $1.348 billion. The Company concluded that the divested businesses met the criteria for discontinued operations, as the dispositions represented a strategic shift in the business in which NRG operates. As such, all prior period results for the transaction have been reclassified as discontinued operations. In connection with the transaction, NRG entered into a transition services agreement to provide certain corporate services to the divested businesses.

As a result of the sale of NRG Yield, Inc., the Company's indirect ownership interest in the Agua Caliente solar project was reduced from 51% to 35%. As such, the Company no longer controls the project; and accordingly, no longer consolidates the project for financial reporting purposes. The Company recorded its ownership interest as an equity method investment upon deconsolidation resulting in a gain of $8 million.

As part of the agreement to sell NRG Yield and the Renewables Platform, the Company agreed to indemnify NRG Yield for any increase in property taxes for certain solar properties. The indemnity term will expire at various dates between 2029 and 2039. NRG has determined that the payment of this indemnity is probable and has recorded the estimated present value of the obligation as of the closing date of the transaction of $153 million to other non-current liabilities with a corresponding loss from discontinued operations. In addition to the California property tax indemnity, there were additional commitments and advisory fees totaling approximately $50 million. The Company will also retain all costs associated with the development and ownership of the Patriot Wind project until its sale to a third party pursuant to a sale agreement.

Carlsbad

On February 6, 2018, NRG entered into an agreement with NRG Yield and GIP to sell 100% of the membership interests in Carlsbad Energy Holdings LLC, which owned the Carlsbad project, for $387 million of cash consideration, excluding working capital adjustments. The primary condition to close the Carlsbad transaction was the completion of the sale of NRG Yield and the Renewables Platform. As the sale of NRG Yield and the Renewables Platform has closed, the Company concluded that the Carlsbad project met the criteria for discontinued operations and accordingly, the financial information for all current and historical periods has been recast to reflect Carlsbad as a discontinued operation. The Company continued to consolidate Carlsbad for financial reporting purposes until the transaction closed on February 27, 2019. Carlsbad will continue to have a ground lease and easement agreement with NRG. The agreement has an initial term ending in 2039 with two ten year extensions. As a result of the transaction, additional commitments related to the project totaled $23 million.

Summarized results of NRG Yield, Inc. and Renewables Platform and Carlsbad discontinued operations were as follows:



	Year Ended December 31,
(In millions)	2018			2017			2016
Operating revenues	$	909		$	1,164		$	1,165
Operating costs and expenses	(661		)	(1,114		)	(1,023		)
Other expenses	(174		)	(288		)	(261		)
Gain/(loss) from operations of discontinued components, before tax	74			(238		)	(119		)
Income tax expense/(benefit)	4			52			(20		)
Gain/(loss) from discontinued operations, net of tax	70			(290		)	(99		)
Loss on deconsolidation, net of tax	(134		)	—			—
California property tax indemnification	(153		)	—			—
Other Commitments, Indemnification and Fees	(75		)	—			—
Loss on disposal of discontinued operations, net of tax	(362		)	—			—
Loss from discontinued operations, net of tax	$	(292	)	$	(290	)	$	(99	)

The following table summarizes the major classes of assets and liabilities classified as discontinued operations as follows:



(In millions)	December 31, 2018 ^(a)		December 31, 2017 ^(b)
Cash and cash equivalents	$	—	$	224
Restricted Cash	4		229
Accounts receivable, net	10		119
Other current assets	5		81
Current assets - discontinued operations	19		653
Property, plant and equipment, net	590		7,473
Equity investments in affiliates	—		856
Intangible assets, net	9		1,240
Other non-current assets	4		475
Non-current assets - discontinued operations	603		10,044
Current portion of long term debt and capital leases	20		484
Accounts payable	27		169
Other current liabilities	1		159
Current liabilities - discontinued operations	48		812
Long-term debt and capital leases	572		6,536
Other non-current liabilities	2		186
Non-current liabilities - discontinued operations	$	574	$	6,722

(a) Represents the Carlsbad project

(b) Represents the discontinued operations of NRG Yield, NRG's Renewable Platform and the Carlsbad project

Sale of Assets to NRG Yield, Inc. Prior to Discontinued Operations

On June 19, 2018, the Company completed the UPMC Thermal Project and received cash consideration from NRG Yield of $84 million plus an additional $3 million received at final completion in January 2019.

On March 30, 2018, as part of the Transformation Plan, the Company sold to NRG Yield, Inc. 100% of NRG's interests in Buckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar generation project, located in Texas. NRG Yield, Inc. paid cash consideration of approximately $42 million, excluding working capital adjustments, and assumed non-recourse debt of approximately $183 million.

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.

GenOn

On June 14, 2017, 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 controlled GenOn as it was subject to the control of the Bankruptcy Court; and, accordingly, NRG deconsolidated GenOn and its subsidiaries for financial reporting purposes as of such date.

By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn met the criteria for discontinued operations, as this represented a strategic shift in the business in which NRG operated. As such, all prior period results for GenOn have been reclassified as discontinued operations.

Summarized results of discontinued operations were as follows:



	Year Ended December 31,
(In millions)	2018			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)/gain from operations of discontinued components, before tax	—			(154		)	92
Income tax expense	—			9			11
(Loss)/gain from discontinued operations	—			(163		)	81
Interest income - affiliate	3			8			11
Income/(loss) from discontinued operations, net of tax	3			(155		)	92
Pre-tax loss on deconsolidation	—			(208		)	—
Settlement consideration, insurance and services credit	63			(289		)	—
Pension and post-retirement liability assumption	21			(131		)	—
Other	(53		)	(6		)	—
Income/(loss) on disposal of discontinued operations, net of tax	31			(634		)	—
Income/(loss) from discontinued operations, net of tax	$	34		$	(789	)	$	92

GenOn Settlement and Plan Confirmation

Effective July 16, 2018, NRG and GenOn consummated the GenOn Settlement whereby the Company paid GenOn approximately $125 million, which included (i) the settlement consideration of $261 million, (ii) the transition services credit of $28 million and (iii) the return of $15 million of collateral posted to NRG; offset by the (i) $151 million in borrowings under the intercompany secured revolving credit facility, (ii) related accrued interest and fees of $12 million, (iii) remaining payments due under the transition services agreement of $10 million, (iv) $4 million reduction of the settlement payment related to NRG assigning to GenOn approximately $8 million of historical claims against REMA and (v) certain other balances due to NRG totaling $2 million.

GenOn's plan of reorganization was confirmed on December 14, 2018. Pursuant to the confirmed plan, NRG retained the pension liability for GenOn employees for service provided prior to the completion of the reorganization. NRG also retained the liability for GenOn's post-employment and retiree health and welfare benefits. These liabilities were recorded within other non-current liabilities as of December 31, 2018 and 2017. As a result of GenOn's emergence from bankruptcy, NRG is taking a deduction for GenOn tax losses of $9.5 billion, including a worthless stock deduction.

Other than those obligations which survive or are independent of the releases described herein, the GenOn Settlement and the GenOn Chapter 11 plan provide NRG releases from GenOn and each of its debtor and non-debtor subsidiaries.

REMA Plan of Reorganization

On October 16, 2018, REMA and its subsidiaries filed voluntary petitions for chapter 11 relief and a prepackaged plan of reorganization in the United States Bankruptcy Court for the Southern District of Texas. The REMA debtors' plan of reorganization has been formally accepted by REMA's voting creditors and is consistent with the releases NRG received under the GenOn Settlement and the GenOn plan.

GenMA Settlement

The Bankruptcy Court order confirming the plan of reorganization also approved the settlement terms agreed to among the GenOn Entities, NRG, the Consenting Holders, GenOn Mid-Atlantic, and certain of GenOn Mid-Atlantic’s stakeholders, or the GenMA Settlement, and directed the settlement parties to cooperate in good faith to negotiate definitive documentation consistent with the GenMA Settlement term sheet in order to pursue consummation of the GenMA Settlement. The definitive documentation effectuating the GenMA Settlement was finalized and effective as of April 27, 2018. Certain terms of the compromise with respect to NRG and GenOn Mid-Atlantic are as follows:


•	Settlement of all pending litigation and objections to the Plan (including with respect to releases and feasibility);


•	NRG provided $38 million in letters of credit as new qualifying credit support to GenOn Mid-Atlantic; and


•	NRG paid approximately $6 million as reimbursement of professional fees incurred by certain of GenOn Mid-Atlantic's stakeholders in connection with the GenMA Settlement.

Planned Dispositions

On November 1, 2018, the Company offered to Clearway Energy, Inc. its ownership interest in Agua Caliente Borrower 1, LLC, for approximately $120 million, which owns a 35% interest in Agua Caliente, a 290 MW utility-scale solar project located in Dateland, Arizona. The offer expired on January 31, 2019, with no action taken by Clearway Energy, Inc. As a result, the right of first offer agreement with Clearway Energy, Inc. has expired and NRG's interest in Agua Caliente is no longer subject to a right of first offer thereunder.

Dispositions

On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to Diamond Energy Trading and Marketing, LLC for $71 million, net of working capital adjustments, which resulted in a gain of $15 million on the sale. The sale also resulted in the release and return of approximately $119 million of letters of credit, $32 million of parent guarantees, and $4 million of net cash collateral to NRG.

On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for cash proceeds of approximately $16 million and recorded a gain of $17 million. Prior to the sale, Canal 3 entered into a financing arrangement and received cash proceeds of $167 million, of which $151 million was distributed to the Company. The related debt was non-recourse to NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3.

In addition, the Company completed other asset sales for $28 million of cash proceeds during the year ended December 31, 2018.

2016 Dispositions

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 $3 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 $103 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 $6 million remains as of December 31, 2018. 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. The Company's remaining 23.7% interest in EVgo is accounted for as an equity method investment.

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 9, Asset Impairments.

Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2018

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,
	2018				2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets
Notes receivable	$	17	$	14	$	2	$	2
Liabilities
Long-term debt, including current portion ^(a)	$	6,591	$	6,697	$	9,482	$	9,739

(a) 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, 2018 and 2017:



	As of December 31, 2018				As of December 31, 2017
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	6,528	$	169	$	7,432	$	2,307

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, 2018
	Fair Value
	Total		Level 1		Level 2		Level 3
	(In millions)
Investments in securities (classified within other current and non-current assets)	$	39	$	2	$	18	$	19
Nuclear trust fund investments:
Cash and cash equivalents	19		19		—		—
U.S. government and federal agency obligations	46		46		—		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	22		—		22		—
Corporate debt securities	96		—		96		—
Equity securities	312		312		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,042		137		796		109
Interest rate contracts	39		—		39		—
Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	64		—		—		—
Equity securities	8		—		—		—
Total assets	$	1,792	$	517	$	1,075	$	128
Derivative liabilities:
Commodity contracts	$	977	$	224	$	664	$	89
Total liabilities	$	977	$	224	$	664	$	89



	As of December 31, 2017
	Fair Value
	Total		Level 1		Level 2		Level 3

Investments in securities (classified within other current or non-current assets)	$	39	$	3	$	17	$	19
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	744		191		509		44
Interest rate contracts	39		—		39		—
Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	68		—		—		—
Equity securities	8		—		—		—
Total assets	$	1,523	$	616	$	768	$	63
Derivative liabilities:
Commodity contracts	$	674	$	257	$	358	$	59
Interest rate contracts	6		—		6		—
Total liabilities	$	680	$	257	$	364	$	59

The following tables reconcile, for the years ended December 31, 2018 and 2017, 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, 2018
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt Securities		Derivatives^(a)			Total
	(In millions)
Beginning balance as of January 1, 2018	$	19	$	(15	)	$	4
Contracts acquired in XOOM acquisition	—		12			12
Total losses realized/unrealized included in earnings	—		(21		)	(21		)
Purchases	—		41			41
Transfers into Level 3 ^(b)	—		5			5
Transfers out of Level 3 ^(b)	—		(2		)	(2		)
Ending balance as of December 31, 2018	$	19	$	20		$	39
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, 2018	$	—	$	(17	)	$	(17	)


(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, 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	$	(64	)	$	(47	)
Total gains realized/unrealized included in earnings	2		37			39
Purchases	—		(4		)	(4		)
Contracts reclassified to held-for-sale			4			4
Transfers into Level 3 ^(b)	—		(1		)	(1		)
Transfer out of Level 3 ^(b)	—		13			13
Ending balance as of December 31, 2017	$	19	$	(15	)	$	4
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	$	—	$	1		$	1


(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

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 10% of derivative assets and 9% 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, 2018 and December 31, 2017 the credit reserve did not result in a significant change in fair value.

The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2018, 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, 2018 and 2017:



	Significant Unobservable Inputs
	December 31, 2018
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	89	$	75	Discounted Cash Flow	Forward Market Price (per MWh)	$	1		$	214	$	31
FTRs	20		14		Discounted Cash Flow	Auction Prices (per MWh)	(90		)	34		—
	$	109	$	89



	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	$	33	$	47	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	142	$	24
FTRs	11		12		Discounted Cash Flow	Auction Prices (per MWh)	(28		)	46		—
	$	44	$	59

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2018 and 2017:



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, 2018, the Company recorded $287 million of cash collateral posted and $33 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, 2018, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $301 million and NRG held collateral (cash and letters of credit) against those positions of $123 million, resulting in a net exposure of $180 million. Approximately 66% of the Company's exposure before collateral is expected to roll off by the end of 2020. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.



Category	Net Exposure ^{(a) (b)} (% of Total)
Utilities, energy merchants, marketers and other	89	%
Financial institutions	11
Total	100	%



Category	Net Exposure^{(a) (b)} (% of Total)
Non-Investment grade/Non-Rated	51	%
Investment grade	49
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.

The Company currently has no exposure to any individual wholesale counterparty in excess of 10% of the total net exposure discussed above as of December 31, 2018. 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 contracts, including California tolling agreements 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, 2018, aggregate credit risk exposure managed by NRG to these counterparties was approximately $434 million for the next five years. This amount excludes potential credit exposures for projects with long-term PPAs that have not reached commercial operations and any exposure for entities classified as a discontinued operation.

NRG through its unconsolidated affiliates Ivanpah and Agua Caliente has exposure to PG&E of approximately $321 million for the next five years. As a result of the bankruptcy filing by PG&E on January 29, 2019, it is uncertain whether and to what extent the bankruptcy may have on these contracts. For further discussion see Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities.

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, 2018, 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 $85 million, $68 million, and $45 million for the years ending December 31, 2018, 2017, and 2016, 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, 2018

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 NPNS accounting. 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 of a portion of anticipated power purchases for the Company's retail sales;


•	Fixing the price for a portion of anticipated future electricity sales that provides an acceptable return on the Company's electric generation operations; and


•	Fixing the price of a portion of anticipated fuel purchases for the operation of the Company's power plants.

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, 2018, 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 2034;


•	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 2029.

Also, as of December 31, 2018, 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 2034;


•	Power tolling contracts through 2029;


•	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, 2018, NRG's derivative assets consisted of interest rate derivative instruments on recourse debt extending through 2021.

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, 2018 and 2017. 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, 2018			December 31, 2017
		(In millions)
Emissions	Short Ton	(2		)	1
Renewables Energy Certificates	Certificates	1			—
Coal	Short Ton	13			21
Natural Gas	MMBtu	(330		)	(20		)
Oil	Barrels	1			—
Power	MWh	1			23
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	1,000		$	1,060
Equity	Shares	—			1

The increase in the natural gas position was primarily the result of additional generation hedge positions.

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, 2018		December 31, 2017		December 31, 2018		December 31, 2017
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	17	$	8	$	—	$	1
Interest rate contracts long-term	22		31		—		5
Commodity contracts current	747		616		673		536
Commodity contracts long-term	295		128		304		138
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	1,081	$	783	$	977	$	680

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, 2018	(In millions)
Commodity contracts:
Derivative assets	$	1,042		$	(778	)	$	(31	)	$	233
Derivative liabilities	(977		)	778			114			(85		)
Total commodity contracts	65			—			83			148
Interest rate contracts:
Derivative assets	39			—			—			39
Total interest rate contracts	39			—			—			39
Total derivative instruments	$	104		$	—		$	83		$	187



	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	$	744		$	(578	)	$	(11	)	$	155
Derivative liabilities	(674		)	578			72			(24		)
Total commodity contracts	70			—			61			131
Interest rate contracts:
Derivative assets	39			—			—			39
Derivative liabilities	(6		)	—			—			(6		)
Total interest rate contracts	33			—			—			33
Total derivative instruments	$	103		$	—		$	61		$	164

Accumulated Other Comprehensive Income

The following table summarizes the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:



	Interest Rate Contracts
	2018			2017			2016
	(In millions)
Accumulated OCI beginning balance	$	(54	)	$	(66	)	$	(101	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	8			12			21
Mark-to-market of cash flow hedge accounting contracts	21			—			14
Sale of NRG Yield and Renewables	$	25		$	—		$	—
Accumulated OCI ending balance, net of $0, $8 and $16 tax	$	—		$	(54	)	$	(66	)

Amounts reclassified from accumulated OCI into income are recorded in discontinued operations.

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 certain yield interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result, the Company de-designated these derivatives as cash flow hedges as of December 31, 2016, and prospectively marked these derivatives to market through the income statement until the assets were sold.

The Company's regression analysis for certain Yield interest rate swaps, while positively correlated, no longer contain matching terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated these derivatives as cash flow hedges as of April 28, 2017, and prospectively marked these derivatives to market through the income statement until the assets were sold.

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,
	2018			2017			2016
	(In millions)
Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(73	)	$	47		$	(128	)
Reversal of acquired gain positions related to economic hedges	(10		)	—			(12		)
Net unrealized gains on open positions related to economic hedges	97			159			12
Total unrealized mark-to-market gains/(losses) for economic hedging activities	14			206			(128		)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(12		)	(25		)	10
Net unrealized gains on open positions related to trading activity	29			14			18
Total unrealized mark-to-market gains/(losses) for trading activity	17			(11		)	28
Total unrealized gains/(losses)	$	31		$	195		$	(100	)



	Year Ended December 31,
	2018			2017			2016
	(In millions)
Unrealized (losses)/gains included in operating revenues	$	(113	)	$	241		$	(608	)
Unrealized gains/(losses) included in cost of operations	144			(46		)	508
Total impact to statement of operations — energy commodities	$	31		$	195		$	(100	)
Total impact to statement of operations — interest rate contracts	$	—		$	4		$	(8	)

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, 2018, the $97 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, 2017, the $159 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 $12 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.

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, 2018 was $16 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2018 was $14 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 $11 million as of December 31, 2018.

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

Nuclear Decommissioning Trust Fund

12 Months Ended

Dec. 31, 2018

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 for the securities held in the trust funds, as well as information about the contractual maturities of those securities.



	As of December 31, 2018							As of December 31, 2017
(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	$	19	$	—	$	—	—	$	47	$	—	$	—	—
U.S. government and federal agency obligations	46		1		—		12	43		1		—		11
Federal agency mortgage-backed securities	100		1		2		23	82		1		1		23
Commercial mortgage-backed securities	22		—		1		22	14		—		—		20
Corporate debt securities	96		1		2		11	99		2		1		11
Equity securities	376		231		1		—	402		272		—		—
Foreign government fixed income securities	4		—		—		9	5		—		—		9
Total	$	663	$	234	$	6		$	692	$	276	$	2

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,
	2018			2017			2016
	(In millions)
Realized gains	$	17		$	22		$	26
Realized (losses)	(13		)	(8		)	(11		)
Proceeds from sale of securities	513			501			510

Inventory

12 Months Ended

Dec. 31, 2018

Inventory Disclosure [Abstract]

Inventory

Inventory consisted of:



	As of December 31,
	2018		2017
	(In millions)
Fuel oil	$	74	$	86
Coal	97		110
Natural gas	28		24
Spare parts	213		233
Total Inventory	$	412	$	453

The Company recorded a lower of weighted average cost or market adjustment related to fuel oil for the years ended, December 21, 2018 and 2017 of $3 million and $33 million respectively.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2018

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
	2018			2017			Lives
	(In millions)
Facilities and equipment	$	3,763		$	6,904		1-40 Years
Land and improvements	347			468
Nuclear fuel	212			235			5 Years
Office furnishings and equipment	431			421			2-10 Years
Construction in progress	106			201
Total property, plant, and equipment	4,859			8,229
Accumulated depreciation	(1,811		)	(2,255		)
Net property, plant, and equipment	$	3,048		$	5,974

The Company recorded long-lived asset impairments during the years ended December 31, 2018 and 2017, as further described in Note 9, Asset Impairments.

Asset Impairments	12 Months Ended
Asset Impairments	Dec. 31, 2018
Asset Impairment Charges [Abstract]
Asset Impairments	Asset Impairments 2018 Impairment Losses Guam — During the fourth quarter of 2018, the Company concluded its wholly-owned subsidiary, NRG Solar Guam, LLC, was held for sale after 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, 2018 based on the contractual sale price, which resulted in an impairment loss of $12 million. On February 20, 2019, the Company completed the sale of Guam for cash consideration of approximately $8 million. Keystone and Conemaugh — On September 5, 2018, the Company sold its approximately 3.7% interests in the Keystone and Conemaugh generating stations. NRG recorded impairment losses of $14 million for Keystone and $14 million for Conemaugh to adjust the carrying amount of the assets to fair value based on the contractual sale price. Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against the NYPSC, which challenged the legality of its contract with Dunkirk. The lawsuit was later dropped and development continued, but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection study process. The NYISO studies have concluded that extensive electric system upgrades would be necessary for the station to return to service. This would cause the Company to incur a material increase in cost and delay the project schedule that would render the project impractical. Consequently, the Company has recorded an impairment loss of $46 million, reducing the carrying amount of the related assets to $0. Other Impairments — As of December 31, 2018, the Company recorded additional asset impairment losses of approximately $13 million and impairment losses on equity method investments of $15 million. 2017 Impairment Losses South Texas Project — 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. 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 $0 during the second quarter of 2017. Subsequent to the MIPA termination, BTEC filed claims against NRG Texas Power LLC with respect to the termination of the MIPA and NRG filed counterclaims against BTEC as further described in Note 21, Commitments and Contingencies. On June 7, 2018, the parties resolved all claims and counterclaims in the lawsuit. 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. Other Impairments — During the year ended 2017, the Company recorded impairment losses of $29 million in connection with renewable assets that were not divested as part of the sale of NRG Yield and the Renewables Platform. In addition, the Company recorded an impairment loss of $20 million related to excess SO₂ allowances and $10 million in impairment losses for other investments. 2016 Impairment Losses Rockford — As described in Note 3, Acquisitions, Discontinued Operations 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 their fair market value. 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. 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 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 connection with the preparation of the annual budget, the Company noted that due to the anticipated difficulty in refinancing Sherbino's debt, the project's fair value had decreased significantly below its carrying amount and determined the impairment to be other-than-temporary. Accordingly, the Company determined that an impairment existed and recorded an impairment loss on its investment in Sherbino of $70 million. Other Impairments — During 2016, the Company recorded other impairment losses of $29 million in connection with renewable assets that were not divested as part of the sale of NRG Yield and the Renewables Platform. In addition, the Company also recorded impairment losses of $23 million in excess SO₂allowances, $19 million for other intangible assets, $19 million in previously purchased solar panels and $22 million in other investments.

Goodwill and Other Intangibles

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangibles

Goodwill

NRG's goodwill balance was $573 million and $539 million as of December 31, 2018 and 2017, respectively. The increase in goodwill is due to the acquisition of XOOM. As of December 31, 2018 and 2017, NRG had approximately $366 million and $460 million, respectively, of goodwill that is deductible for U.S. income tax purposes in future periods. As of December 31, 2018, goodwill consisted of $165 million associated with the acquisition of Midwest Generation and $408 million for Retail business acquisitions, including Texas non-commodity and XOOM.

2017 Impairments of Goodwill

BETM — During the fourth quarter of 2017, the Company concluded that BETM was held for sale following 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 was included within non-current assets held-for-sale 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 Generation reporting unit, reducing the goodwill balance for Texas Generation to zero.

In connection with the annual impairment assessment, the Company performed step one of the two-step impairment test for the Texas Generation 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 Generation 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 annual budget, 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 Generation 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 Generation 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, 2018, primarily reflect intangible assets established with the acquisitions of various companies, including Texas Genco, Reliant Energy, Green Mountain Energy, Dominion, XOOM, Discount Power, Energy Alternatives, Energy Plus, Energy Systems, Energy Curtailment Specialists, Pioneer Energy, Stat Energy and Source Power & Gas. Intangible assets are comprised of the following:


•	Energy supply contracts — 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.


•	Customer contracts — 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. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.


•	Marketing partnerships — 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 — These intangibles are amortized to depreciation and amortization expense on a straight-line basis.

•

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, 2018, the Company recorded an impairment loss of $5 million to reduce the value of excess SO₂ allowances to zero.


•	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.


•	Other — Consists of renewable energy credits and costs to extend the operating license for STP Units 1 and 2.

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



				Contracts
Year Ended December 31, 2018	Emission Allowances			Fuel			Customer Contracts			Customer Relationships			Marketing Partnerships			Trade Names			Other			Total

January 1, 2018	$	755		$	49		$	1		$	768		$	88		$	342		$	77		$	2,080
Purchases	33			—			—			—			—			—			28			61
Acquisition of businesses^(a)	—			—			—			122			43			13			—			178
Usage	(1		)	—			—			—			—			—			(26		)	(27		)
Write-off of fully amortized balances	(107		)	—			—			(411		)	—			(10		)	—			(528		)
Impairment	(5		)	—			—			(1		)	—			—			—			(6		)
Other	(16		)	—			—			—			—			—			—			(16		)
December 31, 2018	659			49			1			478			131			345			79			1,742
Less accumulated amortization	(515		)	(45		)	(1		)	(314		)	(61		)	(195		)	(20		)	(1,151		)
Net carrying amount	$	144		$	4		$	—		$	164		$	70		$	150		$	59		$	591

(a) The weighted average life of acquired intangibles is: customer relationships 6 years, trade names 7 years, and marketing partnerships 14 years



				Contracts
Year Ended December 31, 2017	Emission Allowances			Energy Supply			Fuel			Customer Contracts			Customer Relationships			Marketing Partnerships			Trade Names			Other			Total
	(In millions)
January 1, 2017	$	780		$	54		$	72		$	1		$	750		$	88		$	342		$	75		$	2,162
Purchases	27			—			—			—			—			—			—			32			59
Acquisition of businesses	—			—			—			—			18			—			—			—			18
Usage	(10		)	—			—			—			—			—			—			(28		)	(38		)
Write-off of fully amortized balances	—			(54		)	(23		)	—			—			—			—			—			(77		)
Impairment	(20		)	—			—			—			—			—			—			—			(20		)
Other	(22		)	—			—			—			—			—			—			(2		)	(24		)
December 31, 2017	755			—			49			1			768			88			342			77			2,080
Less accumulated amortization	(583		)	—			(45		)	(1		)	(693		)	(54		)	(182		)	(15		)	(1,573		)
Net carrying amount	$	172		$	—		$	4		$	—		$	75		$	34		$	160		$	62		$	507

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



	Years Ended December 31,
Amortization	2018		2017		2016
	(In millions)
Emission allowances	$	39	$	71	$	62
Energy supply contracts	—		1		6
Fuel contracts	—		1		1
Customer relationships	32		34		48
Marketing partnerships	9		5		8
Trade names	23		23		23
Other	4		3		9
Total amortization	$	107	$	138	$	157

The following table presents estimated amortization of NRG's intangible assets for each of the next five years:



Year Ended December 31,	Emission Allowances		Fuel Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other		Total
	(In millions)
2019	$	48	$	—	$	38	$	11	$	24	$	3	$	124
2020	37		1		39		11		25		3		116
2021	43		—		33		10		24		3		113
2022	50		—		23		10		24		3		110
2023	49		1		26		10		24		3		113

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, 2018 and 2017, the value of emission allowances held-for-sale is $12 million and $9 million, respectively, 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 $121 million acquired in the acquisition of Midwest Generation. These out-of-market contracts are amortized to cost of operations. As of December 31, 2018 and 2017, the Company had accumulated amortization for out-of-market contracts of $37 million and $29 million, respectively. Upon adoption of ASC 842, Leases, on January 1, 2019, out-of-market lease contracts are included as a component of right-of-use assets.

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



Year Ended December 31,	Leases

2019	$	8
2020	8
2021	8
2022	8
2023	8

Debt and Capital Leases

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt and Capital Leases

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



(In millions, except rates)	December 31, 2018			December 31, 2017			December 31, 2018 interest rate %^(a)

Recourse debt:
Senior Notes, due 2022	$	—		$	992		6.250
Senior Notes, due 2024	733			733			6.250
Senior Notes, due 2026	1,000			1,000			7.250
Senior Notes, due 2027	1,230			1,250			6.625
Senior Notes, due 2028	821			870			5.750
Convertible Senior Notes, due 2048	575			—			2.750
Term loan facility, due 2023	1,698			1,872			L+1.75
Tax-exempt bonds	466			465			4.125 - 6.00
Subtotal recourse debt	6,523			7,182
Non-recourse debt:
Ivanpah, due 2033 and 2038^(b)	—			1,073			2.285 - 4.256
Agua Caliente, due 2037^(c)	—			818			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	86			89			5.430
Midwest Generation, due 2019	48			152			4.390
Other ^(d)	34			180			various
Subtotal all non-recourse debt	168			2,312
Subtotal long-term debt (including current maturities)	6,691			9,494
Capital leases	1			5			various
Subtotal long-term debt and capital leases (including current maturities)	6,692			9,499
Less current maturities	(72		)	(204		)
Less debt issuance costs	(70		)	(103		)
Discounts	(101		)	(12		)
Total long-term debt and capital leases	$	6,449		$	9,180

(a) As of December 31, 2018, L+ equals 1-month LIBOR plus 1.75%

(b) The Company deconsolidated Ivanpah during the second quarter of 2018

(d) Guam was reclassified to held for sale during the fourth quarter of 2018

Debt includes the following discounts:



	As of December 31,
	2018			2017
	(In millions)
Term loan facility, due 2023	$	(4	)	$	(7	)
Midwest Generation, due 2019	(1		)	(5		)
Convertible Senior Notes, due 2048	(96		)	—
Total discounts	$	(101	)	$	(12	)

Consolidated Annual Maturities

As of December 31, 2018, annual payments based on the maturities of NRG's debt and capital leases are expected to be as follows:



	(In millions)
2019	$	74
2020	26
2021	27
2022	25
2023	1,635
Thereafter	4,905
Total	$	6,692

Recourse Debt

Issuance of 2048 Convertible Senior Notes

During the second quarter of 2018, NRG issued $575 million in aggregate principal amount of 2.75% Convertible Senior Notes due 2048, or the Convertible Notes. The Convertible Notes are convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at an initial conversion price of $47.74 per common share, which is equivalent to an initial conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of Convertible Notes. Interest on the Convertible Notes is payable semi-annually in arrears on June 1 and December 1 of each year, commencing on December 1, 2018. The Convertible Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The Convertible Notes are guaranteed by certain NRG subsidiaries. Prior to the close of business on the business day immediately preceding December 1, 2024, the Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:

•from December 1, 2024 until the close of business on the second scheduled trading day immediately before June 1, 2025; and

•from December 1, 2047 until the close of business on the second scheduled trading day immediately before the maturity date.

The Convertible Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options. Under ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The carrying amount of the liability component at issuance date of $472 million was calculated by estimating the fair value of similar liabilities without a conversion feature. The residual principal amount of the notes of $103 million was allocated to the equity component with offset to debt discount. The debt discount will be amortized to interest expense using the effective interest method over seven years which is determined to be the expected life of the Convertible Notes.

The Company incurred approximately $12 million in transaction costs in connection with the issuance of the notes. These costs were allocated to the liability and equity components in proportion to the allocation of proceeds. Transaction costs of $10 million, allocated to the liability component, were recognized as deferred financing costs and are amortized over the seven years. Transaction costs of $2 million, allocated to the equity component, were recognized as a reduction of additional paid-in capital.

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.

2018 Senior Note Repurchases

During the year ended December 31, 2018 the Company completed senior note repurchases, as detailed in the table below. In addition, during the year ended December 31, 2018, a $38 million loss on debt extinguishment was recorded for these repurchases, which included the write-off of previously deferred financing costs of $7 million.



	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
In millions, except percentages
5.750% senior notes due 2028	$	29	$	30	99.24	%
6.250% senior notes due 2022	14		15		103.25	%
Total at June 30, 2018	$	43	$	45
6.250% senior notes due 2022	493		512		103.13	%
5.750% senior notes due 2028	20		20		99.13	%
6.625% senior notes due 2027	20		21		103.06	%
Total at September 30, 2018	$	576	$	598
6.250% senior notes due 2022	485		508		103.13	%
Total at December 31, 2018	$	1,061	$	1,106

(a) Includes accrued interest of $14 million

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. 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 percentages
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 accrued interest of $29 million

Senior Notes Early Redemption

As of December 31, 2018, NRG had the following outstanding issuances of senior notes with an early redemption feature, or Senior Notes:

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

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

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

iv.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.

2024 Senior Notes

At any time prior to May 1, 2019, NRG may redeem up to 35% of the aggregate principal amount 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 the previous 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 term 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. 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%. On March 21, 2018, NRG again repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%.

•

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 both pay interest at a rate of LIBOR plus 2.25%. On May 7, 2018, NRG entered into the third amendment agreement extending the maturity date of the Tranche A revolving facility to June 30, 2021, for the Tranche A accepting lender.

In accordance with the terms of the Credit Agreement, on October 5, 2018, the Company initiated an asset sale offer to purchase a portion of its Term Loan following the sale of NRG Yield and the Renewables Platform. The offer expired on November 5, 2018 and $260 million of Term Loan holders accepted the offer. As a result, the Company prepaid $155 million of Term Loans as part of its de-leveraging plan, as well as established an incremental first lien secured term loan facility under the Senior Credit Facility in the aggregate principal amount of $105 million on the same terms and conditions to stay within its debt reduction target. In addition, a $3 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $2 million.

In accordance with the terms of the credit agreement, upon the consummation of the sales of the South Central Portfolio and Carlsbad, the Company will initiate asset sale offers to purchase a portion of its Term Loan. The Company has one year from the dates of each sale to initiate the offer.

Tax Exempt Bonds



	As of December 31,
	2018		2017		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	33		32		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	$	466	$	465

Non-Recourse Debt

The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2018. All of NRG's non-recourse debt is secured by the assets in the respective project subsidiaries as further described below.

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, 2018, $48 million was outstanding.

Agua Caliente Borrower I

On January 22, 2019, the lenders of the Agua Borrower I debt notified the Company of certain defaults under the financing agreement as it relates to the bankruptcy filing made by PG&E on January 29, 2019. PG&E is the offtaker of the underlying contracts, which are material. The financing was entered into along with Agua Caliente Borrower 2, LLC, a subsidiary of Clearway Energy Inc., which is joint and several to the parties. The Company is working with the lenders to determine a path forward.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

The Company's AROs are primarily related to the environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities and future dismantlement of equipment on leased property. 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 treatment per ASC 980, Regulated Operations. Nuclear decommissioning ARO liabilities were $282 million and $269 million as of December 31, 2018 and 2017, respectively.

The following table represents the balance of ARO obligations as of December 31, 2018 and 2017, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2018:



	(In millions)
Balance as of December 31, 2017	$	679
Revisions in estimates for current obligations	(27		)
Additions	9
Spending for current obligations	(27		)
Accretion — Expense	30
Accretion — Nuclear decommissioning	15
Balance as of December 31, 2018	$	679

Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2018

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 NRG participate in each of the pension plans, depending upon whether their employment is covered by a bargaining agreement.

NRG and GenOn entered into a Restructuring Support Agreement in which NRG agreed to retain GenOn's pension liability for service provided by GenOn employees prior to the completion of the GenOn reorganization. NRG determined that the retention of this liability was probable and recorded the estimated accumulated pension benefit obligation as of December 31, 2017 of $92 million, which reflects a $13 million contribution made by NRG to the plan in 2017, in other non-current liabilities with a corresponding loss from discontinued operations. NRG also agreed to retain the liability for GenOn's post-employment and retiree health and welfare benefits with the obligation capped at $25 million. NRG's obligation for both of these liabilities was revalued at GenOn's emergence from bankruptcy.

NRG expects to contribute $41 million to the Company's pension plans in 2019, of which $13 million relates to 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
	2018			2017			2016
	(In millions)
Service cost benefits earned	$	23		$	26		$	30
Interest cost on benefit obligation	44			43			43
Expected return on plan assets	(62		)	(58		)	(60		)
Amortization of unrecognized net loss	—			4			2
Settlement/curtailment expense	7			—			—
Net periodic benefit cost	$	12		$	15		$	15



	Year Ended December 31,
	Other Postretirement Benefits
	2018			2017			2016
	(In millions)
Service cost benefits earned	$	1		$	1		$	2
Interest cost on benefit obligation	4			4			6
Amortization of unrecognized prior service credit	(10		)	(9		)	(5		)
Amortization of unrecognized net (gain)/loss	—			(1		)	—
Curtailment gain	(10		)	—			—
Net periodic benefit (credit)/cost	$	(15	)	$	(5	)	$	3

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
	2018			2017			2018			2017
	(In millions)
Benefit obligation at January 1	$	1,329		$	1,241		$	128		$	128
Service cost	23			26			1			1
Interest cost	44			43			4			4
Plan amendments	17			—			(28		)	(1		)
Actuarial (gain)/loss	(95		)	77			(6		)	6
Employee and retiree contributions	—			—			3			3
Curtailment gain	(20		)	—			(7		)	—
Benefit payments	(76		)	(58		)	(12		)	(13		)
Benefit obligation at December 31	1,222			1,329			83			128
Fair value of plan assets at January 1	1,104			953			—			—
Actual return on plan assets	(80		)	173			—			—
Employee and retiree contributions	—			—			3			3
Employer contributions	33			36			9			10
Benefit payments	(76		)	(58		)	(12		)	(13		)
Fair value of plan assets at December 31	981			1,104			—			—
Funded status at December 31 — excess of obligation over assets	$	(241	)	$	(225	)	$	(83	)	$	(128	)
Less: GenOn postretirement obligation^(a)	—			—			—			38
Add: Retained obligation in bankruptcy proceeding^(a)	—			—			—			(25		)
Net obligation for NRG	$	(241	)	$	(225	)	$	(83	)	$	(115	)

(a)

NRG's liability for GenOn's other postretirement benefit plans was capped at $25 million, with the final liability assumed determined as of GenOn's emergence from bankruptcy. As of December 31, 2017, the liability was $38 million so NRG's obligation was recorded at the $25 million cap. Upon emergence, the retained liability was $23 million, therefore NRG is obligated for the full retained liability of the plans.

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



	As of December 31,
	Pension Benefits				Other Postretirement Benefits
	2018		2017		2018		2017
	(In millions)
Current liabilities	$	—	$	—	$	7	$	7
Less: GenOn other postretirement benefits	—		—		—		(3		)
Total current liabilities	$	—	$	—	$	7	$	4

Non-current liabilities	$	241	$	225	$	76	$	121
Less: GenOn other postretirement benefits	—		—		—		(10		)
Total non-current liabilities	$	241	$	225	$	76	$	111

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
	2018		2017			2018			2017
	(In millions)
Net loss/(gain)	$	90	$	53		$	(9	)	$	(4	)
Prior service cost/(credit)	3		3			(53		)	(37		)
Total accumulated OCI	$	93	$	56		$	(62	)	$	(41	)
Less: GenOn (deconsolidated June 14, 2017)	—		(22		)	—			10
Net accumulated OCI	$	93	$	34		$	(62	)	$	(31	)

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



	Year Ended December 31,
	Pension Benefits						Other Postretirement Benefits
	2018			2017			2018			2017
	(In millions)
Net actuarial loss/(gain)	$	47		$	(37	)	$	(5	)	$	6
Amortization of net actuarial (gain)/loss	—			(4		)	—			1
Curtailment	(27		)	—			2			—
Prior service credit	17			—			(28		)	(1		)
Amortization of prior service cost	—			—			10			9
Total recognized in OCI	$	37		$	(41	)	$	(21	)	$	15
Less: GenOn (deconsolidated June 14, 2017)	—			15			$	—		$	2
Net recognized in OCI	$	37		$	(26	)	$	(21	)	$	17
Less: GenOn post deconsolidation net periodic benefit cost	—			—			—			1
Net periodic benefit cost/(credit)	12			15			(15		)	(5		)
Net recognized in net periodic pension cost/(credit) and OCI	$	49		$	(11	)	$	(36	)	$	13

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 $4 million and $0 million, respectively. 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 $13 million, respectively.

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



	As of December 31,
	Pension Benefits
	2018		2017
	(In millions)
Projected benefit obligation	$	1,222	$	1,329
Accumulated benefit obligation	1,188		1,255
Fair value of plan assets	981		1,104

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, 2018
	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	$	—	$	183	$	183
Common/collective trust investment — non-U.S. equity	—		53		53
Common/collective trust investment — non-core assets	—		117		117
Common/collective trust investment — fixed income	—		256		256
Short-term investment fund	12		—		12
Subtotal fair value	$	12	$	609	$	621
Measured at net asset value practical expedient
Common/collective trust investment — non-U.S. equity					70
Common/collective trust investment — fixed income					249
Common/collective trust investment — non-core assets					16
Partnerships/joint ventures					25
Total fair value					$	981



	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

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	2018		2017		2018		2017
Discount rate	4.38	%	3.71	%	4.37	%	3.71	%
Rate of compensation increase	3.00	%	3.00	%	—	%	—
Health care trend rate	—		—		7.8% grading to 4.5% in 2025		8.2% grading to 4.5% 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	2018		2017		2016		2018	2017		2016
Discount rate	3.71%/4.04%		4.26	%	4.52	%	3.71%/4.08%	4.29	%	4.55	%
Expected return on plan assets	6.17	%	6.85	%	6.65	%	—	—		—
Rate of compensation increase	3.00	%	3.00	%	3.00	%	—	—		—
Health care trend rate	—		—		—		8.2% grading to 4.5% in 2025	7.0% grading to 5.0% in 2025		7.25% grading to 5.0% in 2025

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 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, 2018:



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)
2019	$	72	$	7	$	—
2020	76		7		—
2021	79		7		—
2022	82		6		—
2023	85		6		—
2024-2028	418		26		1

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one-percentage-point change in assumed health care cost trend rates is immaterial on total service and interest costs components but would have the following effect:



	1-Percentage- Point Increase	1-Percentage- Point Decrease
	(In millions)
Effect on postretirement benefit obligation	5	(4	)

STP Defined Benefit Plans

NRG has a 44% undivided ownership interest in STP, as discussed further in Note 26, Jointly Owned Plants. STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan, as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. For the years ended December 31, 2018 and December 31, 2017, NRG reimbursed STPNOC $13 million and $8 million, respectively, for its contribution to the plans. In 2019, NRG expects to reimburse STPNOC $18 million for its contribution to 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
	2018			2017			2018			2017
	(In millions)
Funded status — STPNOC benefit plans	$	(78	)	$	(76	)	$	(19	)	$	(24	)
Net periodic benefit cost/(credit)	8			8			(7		)	(3		)
Other changes in plan assets and benefit obligations recognized in other comprehensive (loss)/income	(7		)	(6		)	2			5

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,
	2018		2017		2016
	(In millions)
Company contributions to defined contribution plans	$	28	$	56	$	55

Capital Structure

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Capital Structure

For the period from December 31, 2015 to December 31, 2018, 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, 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
Shares issued under ESPP	—	175,862		175,862
Shares issued under LTIPs	1,965,752	—		1,965,752
Share repurchases	—	(35,234,664	)	(35,234,664	)
Balance as of December 31, 2018	420,288,886	(136,638,847	)	283,650,039

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, 2018:



Equity Instrument	Common Stock Reserve Balance
Long-term incentive plans	17,631,031

Common stock dividends — In the first quarter of 2016 the Company paid quarterly dividend 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. The Company paid $0.030 dividend per common share for the second quarter of 2016 through the fourth quarter of 2018.

On January 23, 2019, 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, 2019, to stockholders of record as of February 1, 2019

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. Beginning January 2018, NRG suspended the ESPP. As of December 31, 2018, there remained 2,931,188 shares of treasury stock reserved for issuance under the ESPP.

Share Repurchases — In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. In addition, the Company's board of directors authorized in February 2019 an additional $1.0 billion share repurchase program to be executed in 2019.

The following table summarizes the shares repurchased under the 2018 program, including shares repurchased under two completed accelerated repurchase agreements:



	Total number of shares purchased	Average price paid per share		Amounts paid for shares purchased (in millions)
Open market repurchases	11,097,631			$	396
Shares repurchased under May 24, 2018 Accelerated Repurchase Agreement	10,829,903			354
Shares repurchased under September 5, 2018 Accelerated Repurchase Agreement	13,307,130			500
Total Share Repurchases as of December 31, 2018	35,234,664			1,250
Additional open market repurchases through February 28, 2019	6,153,415			250
Total Share Repurchases as of February 28, 2019	41,388,079	$	36.24	$	1,500

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 $345 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 was reflected in net loss available to NRG common stockholders in the calculation of earnings per share for the year ended December 31, 2016.

The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended December 31, 2018, 2017, and 2016:



	(In millions)
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	$	—
Balance as of December 31, 2018	$	—

Investments Accounted for by the Equity Method and Variable Interest Entities

12 Months Ended

Dec. 31, 2018

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 a number of elements including impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates.

The following table summarizes NRG's equity method investments as of December 31, 2018:



Name	Economic Interest		Investment Balance
			(In millions)
Agua Caliente	35.0	%	200
Gladstone	37.5	%	140
Ivanpah Master Holdings, LLC	54.5	%	37
Watson Cogeneration Company	49.0	%	17
Midway-Sunset Cogeneration Company	50.0	%	12
Other^(a)	Various		6
Total equity investments in affiliates			$	412

(a) Refer to Note 9, Asset Impairments, for discussion of NRG's investment in Petra Nova Parish Holdings, LLC



	As of December 31,
	2018		2017
	(In millions)
Undistributed earnings from equity investments	$	34	$	38

PG&E Bankruptcy - The Company's Agua Caliente and Ivanpah projects are party to PPAs with PG&E. Both projects have project financing with the U.S. DOE. On January 29, 2019, PG&E Corp. and subsidiary utility PG&E filed for Chapter 11 bankruptcy protection. As part of their filing, PG&E asked the Bankruptcy Court to confirm "exclusive jurisdiction" over their "rights to reject" PPAs or other contracts regulated by FERC. As a result of the bankruptcy filing, the Agua Caliente and Ivanpah projects have issued notices of events of default under their respective loan agreements. The Company is working with its partners on the projects and the loan counterparties, however, given the uncertainty involved in bankruptcy proceedings, it is uncertain whether, and to what extent, PG&E's bankruptcy may in the future impact the PPAs and have any resulting impact on the Agua Caliente and Ivanpah projects. NRG's maximum exposure to loss is limited to its equity investment, which was $200 million for Agua Caliente and $37 million for Ivanpah. See Note 11, Debt and Capital Leases for further discussion on Agua Caliente.

Variable Interest Entities

NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, Consolidation, for which NRG is not the primary beneficiary, under the equity method.

Through its consolidated subsidiary, NRG Solar Ivanpah LLC, NRG owns a 54.5% interest in Ivanpah Master Holdings, LLC, or Ivanpah, the owner of three solar electric generating projects located in the Mojave Desert with a total capacity of 393 MW. NRG considers this investment a VIE under ASC 810 and NRG is not considered the primary beneficiary. The Company accounts for its interest under the equity method of accounting.

The Ivanpah solar electric generating projects were funded in large part by loans guaranteed by the U.S. DOE and equity from the projects' partners. During the first quarter of 2018, all interested parties sought a restructuring of Ivanpah's debt in order to avoid a potential event of default with respect to the loans in connection with several recent events. Ensuing negotiations culminated in a settlement during the second quarter of 2018 between the parties which resulted in certain transactions, including the release of reserves totaling $95 million to fund equity distributions to the partners, which reduced the equity at risk, and the prepayment of certain of the debt balance outstanding, and the amendment of certain of Ivanpah's governing documents. The equity distributions and prepayment of debt were funded by the agreed upon release of reserve funds. These events were considered to be a reconsideration event in accordance with ASC 810. As a result, NRG determined that it is not the primary beneficiary and deconsolidated Ivanpah. NRG recognized a loss of $22 million on the deconsolidation and subsequent recognition of Ivanpah as an equity method investment. The deconsolidation of Ivanpah reduced the Company's assets by approximately $1.3 billion, which was primarily property, plant and equipment, and reduced the Company's liabilities by $1.2 billion, which was primarily long-term debt.

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 $140 million as of December 31, 2018.

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 eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies.

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



(In millions)	December 31, 2018		December 31, 2017
Current assets	$	3	$	6
Net property, plant and equipment	76		80
Other long-term assets	28		36
Total assets	107		122
Current liabilities	2		3
Long-term debt	29		30
Other long-term liabilities	7		7
Total liabilities	38		40
Redeemable noncontrolling interests	19		19
Net assets less noncontrolling interests	$	50	$	63

Earnings/(Loss) Per Share

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Earnings/(Loss) Per Share

Basic income/(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 income/(loss) per share is computed in a manner consistent with that of basic income/(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 income/(loss) per share. However, these instruments are included in the denominator for purposes of computing diluted income/(loss) per share under the treasury stock method. The if-converted method was used to determine the dilutive effect of the 2048 Convertible Senior Notes for the year ended December 31, 2018. During 2016, the Company repurchased 100% of the outstanding shares of its 2.822%% preferred stock.

The reconciliation of NRG's basic income/(loss) per share to diluted income/(loss) per share is shown in the following table:



	Year Ended December 31,
	2018		2017			2016
	(In millions, except per share amounts)
Basic income/(loss) per share attributable to NRG common stockholders
Net income/(loss) attributable to NRG Energy, Inc.	$	268	$	(2,153	)	$	(774	)
Dividends for preferred shares	—		—			5
Gain on redemption of 2.822% redeemable perpetual preferred shares	—		—			(78		)
Income/(Loss) Available to Common Stockholders	$	268	$	(2,153	)	$	(701	)
Weighted average number of common shares outstanding-basic	304		317			316
Income/(Loss) per weighted average common share — basic	$	0.88	$	(6.79	)	$	(2.22	)
Diluted income/(loss) per share attributable to NRG common stockholders
Weighted average number of common shares outstanding-basic	304		317			316
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	4		—			—
Total dilutive shares	308		317			316
Income/(Loss) per weighted average common share — diluted	$	0.87	$	(6.79	)	$	(2.22	)

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 income/(loss) per share:



	Year Ended December 31,
	2018	2017	2016
	(In millions of shares)
Equity compensation plans	—	5	5
2048 Convertible Senior Notes	7	—	—
Total	7	5	5

Segment Reporting

12 Months Ended

Dec. 31, 2018

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 into the Generation, Retail and corporate segments. Generation includes all power plant activities, domestic and international, as well as renewables. Retail includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products. Intersegment sales are accounted for at market.

As described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company has determined that the South Central Portfolio, NRG Yield Inc. and its Renewables Platform, Carlsbad, and GenOn all qualified for treatment as discontinued operations. The financial information for all historical periods has been recast to reflect the presentation of 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 year ended December 31, 2018, the Company had one customer in the Generation segment that comprised 11% of the Company's consolidated revenues. During the years ended December 31, 2017 and 2016, the Company had no customer that comprised more than 10% of the Company's consolidated revenues.



	For the Year Ended December 31, 2018
	Retail ^(a)			Generation^(a)			Corporate^(a)			Eliminations			Total
	(In millions)
Operating revenues^(a)	$	7,103		$	3,432		$	11		$	(1,068	)	$	9,478
Operating expenses	5,919			3,019			125			(1,066		)	7,997
Depreciation and amortization	116			272			33			—			421
Impairment losses	1			98			—			—			99
Development costs	1			9			2			(1		)	11
Total operating cost and expenses	6,037			3,398			160			(1,067		)	8,528
Gain on sale of assets	—			2			30			—			32
Operating income/(loss)	1,066			36			(119		)	(1		)	982
Equity in earnings of unconsolidated affiliates	—			10			4			(5		)	9
Impairment losses on investments	—			(15		)	—			—			(15		)
Other income/(expenses), net	—			20			(1		)	(1		)	18
Loss on debt extinguishment	—			—			(44		)	—			(44		)
Interest expense	(3		)	(58		)	(422		)	—			(483		)
Income/(loss) from continuing operations before income taxes	1,063			(7		)	(582		)	(7		)	467
Income tax expense	1			—			6			—			7
Net income/(loss) from continuing operations	1,062			(7		)	(588		)	(7		)	460
Loss from discontinued operations, net of income tax	—			—			(192		)	—			(192		)
Net Income/(loss)	1,062			(7		)	(780		)	(7		)	268
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests	1			9			(5		)	(5		)	—
Net income/(loss) attributable to NRG Energy, Inc.	$	1,061		$	(16	)	$	(775	)	$	(2	)	$	268

Balance sheet
Equity investments in affiliates	$	—		$	412		$	—		$	—		$	412
Capital expenditures	90			267			31			—			388
Goodwill	408			165			—			—			573
Total assets	$	3,291		$	5,735		$	7,003		$	(5,401	)	$	10,628



(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues	$	9	$	1,085	$	(26	)	$	—	$	1,068



	For the Year Ended December 31, 2017
	Retail ^(a)			Generation^(a)			Corporate^(a)			Eliminations			Total
	(In millions)
Operating revenues^(a)	$	6,369		$	3,615		$	13		$	(923	)	$	9,074
Operating expenses	5,377			3,071			243			(925		)	7,766
Depreciation and amortization	110			454			35			(3		)	596
Impairment losses	8			1,526			—			—			1,534
Development costs	3			13			6			—			22
Total operating cost and expenses	5,498			5,064			284			(928		)	9,918
Other income - affiliate	—			—			87			—			87
Gain on sale of assets	—			15			1			—			16
Operating income/(loss)	871			(1,434		)	(183		)	5			(741		)
Equity in (losses)/earnings of unconsolidated affiliates	—			(14		)	5			(5		)	(14		)
Impairment losses on investments	—			(75		)	(4		)	—			(79		)
Other income, net	—			23			28			—			51
Loss on debt extinguishment	—			—			(49		)	—			(49		)
Interest expense	(6		)	(100		)	(451		)	—			(557		)
Income/(loss) from continuing operations before income taxes	865			(1,600		)	(654		)	—			(1,389		)
Income tax (benefit)/expense	(8		)	2			(38		)	—			(44		)
Net income/(loss) from continuing operations	873			(1,602		)	(616		)	—			(1,345		)
Loss from discontinued operations, net of income tax	—			—			(992		)	—			(992		)
Net Income/(loss)	873			(1,602		)	(1,608		)	—			(2,337		)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests	1			4			(189		)	—			(184		)
Net income/(loss) attributable to NRG Energy, Inc.	$	872		$	(1,606	)	$	(1,419	)	$	—		$	(2,153	)

Balance sheet
Equity investments in affiliates	$	—		$	179		$	95		$	(92	)	$	182
Capital expenditures	82			148			20			—			250
Goodwill	374			165			—			—			539
Total assets	$	2,655		$	9,090		$	17,402		$	(5,792	)	$	23,355



(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues	$	4	$	877	$	42	$	—	$	923



	For the Year Ended December 31, 2016
	Retail			Generation^(a)			Corporate^(a)			Eliminations			Total
	(In millions)
Operating revenues^(a)	$	6,330		$	3,633		$	74		$	(1,122	)	$	8,915
Operating expenses	5,162			3,322			353			(1,129		)	7,708
Depreciation and amortization	114			593			52			(3		)	756
Impairment losses	1			452			30			—			483
Development costs	4			15			29			—			48
Total operating costs and expenses	5,281			4,382			464			(1,132		)	8,995
Other income - affiliate	—			—			193			—			193
Loss on sale of assets	(1		)	—			(79		)	—			(80		)
Operating income/(loss)	1,048			(749		)	(276		)	10			33
Equity in (losses)/earnings of unconsolidated affiliates	—			(63		)	45			—			(18		)
Impairment losses on investments	—			(248		)	(20		)	—			(268		)
Other (expense)/income, net	(6		)	22			33			(2		)	47
Loss on debt extinguishment	—			—			(142		)	—			(142		)
Interest expense	6			(96		)	(495		)	2			(583		)
Income/(loss) from continuing operations before income taxes	1,048			(1,134		)	(855		)	10			(931		)
Income tax expense/(benefit)	1			(1		)	25			—			25
Net income/(loss) from continuing operations	$	1,047		$	(1,133	)	(880		)	10			(956		)
Income from discontinued operations, net of income tax	—			—			65			—			65
Net Income/(loss)	1,047			(1,133		)	(815		)	10			(891		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			(1		)	(104		)	(12		)	(117		)
Net income/(loss) attributable to NRG Energy, Inc.	$	1,047		$	(1,132	)	$	(711	)	$	22		$	(774	)



(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues	$	16	$	999	$	107	$	—	$	1,122

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

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



	Year Ended December 31,
	2018			2017			2016
	(In millions, except percentages)
Current
State	$	6		$	19		$	6
Total — current	6			19			6
Deferred
U.S. Federal	(16		)	(60		)	23
State	16			(5		)	(6		)
Foreign	1			2			2
Total — deferred	1			(63		)	19
Total income tax expense/(benefit)	$	7		$	(44	)	$	25
Effective income tax rate	1.5		%	3.2		%	(2.7		)%

The following represents the domestic and foreign components of income/(loss) from continuing operations before income taxes:



	Year Ended December 31,
	2018			2017			2016
	(In millions)
U.S.	$	468		$	(1,406	)	$	(942	)
Foreign	(1		)	17			11
Total	$	467		$	(1,389	)	$	(931	)

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



	Year Ended December 31,
	2018			2017			2016
	(In millions, except percentages)
Income/(loss) from continuing operations before income taxes	$	467		$	(1,389	)	$	(931	)
Tax at federal statutory tax rate	98			(486		)	(326		)
State taxes	18			19			—
Foreign operations	—			2			10
Permanent differences	7			—			—
Tax Act - corporate income tax rate change	—			665			—
Valuation allowance due to corporate income tax rate change	—			(660		)	—
Valuation allowance - current period activities	(106		)	455			382
Impact of non-taxable equity earnings	—			(5		)	22
Book goodwill impairment	—			30			—
Net interest accrued on uncertain tax positions	—			—			1
Production tax credits ("PTC")	(7		)	(8		)	(7		)
Recognition of uncertain tax benefits	1			(5		)	2
State rate change including true-up to current period activity	—			—			(59		)
Alternative minimum tax ("AMT") refundable credit	(4		)	(64		)	—
Other	—			13			—
Income tax expense/(benefit)	$	7		$	(44	)	$	25
Effective income tax rate	1.5		%	3.2		%	(2.7		)%

For the year ended December 31, 2018, NRG's overall effective tax rate was different than the federal statutory tax rate of 21% primarily due to a tax benefit for the change in valuation allowance, the generation of PTCs from various wind facilities and establishment of the previously sequestered AMT credit receivable, partially offset by current state tax expense.

For the year ended December 31, 2017, NRG's overall effective tax rate was different than the federal statutory tax 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 and the generation of PTCs 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 Act.

For the year ended December 31, 2016, NRG's overall effective tax rate was different than the federal statutory tax rate of 35% primarily due to the change in valuation allowance and the impact of non-taxable equity earnings, partially offset by the state tax rate change and the generation of PTCs from various wind facilities.

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



	As of December 31,
	2018			2017
	(In millions)
Deferred tax liabilities:
Emissions allowances	$	15		$	15
Derivatives, net	37			17
Investment in projects	180			337
Discount/premium on notes	—			1
Deferred financing costs	21			2
Other	1			5
Discontinued operations	36			49
Total deferred tax liabilities	290			426
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	134			141
Difference between book and tax basis of property	554			611
Goodwill	11			38
Differences between book and tax basis of contracts	38			52
Pension and other postretirement benefits	87			74
Equity compensation	9			10
Bad debt reserve	14			14
U.S. capital loss carryforwards	—			1
U.S. Federal net operating loss carryforwards	2,241			596
Foreign net operating loss carryforwards	62			66
State net operating loss carryforwards	379			128
Foreign capital loss carryforwards	1			1
Federal and state tax credit carryforwards	381			368
Federal benefit on state uncertain tax positions	6			7
Intangibles amortization (excluding goodwill)	21			98
Interest disallowance carryforward per §163(j) of the Tax Act	102			—
Inventory obsolescence	7			12
Discontinued operations	17			185
Total deferred tax assets	4,064			2,402
Valuation allowance	(3,812		)	(1,855		)
Discontinued operations	19			(8		)
Total deferred tax assets, net of valuation allowance	271			539
Net deferred tax (liability)/asset	$	(19	)	$	113

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



	As of December 31,
	2018			2017
	(In millions)
Deferred tax asset — continuing operations	$	46		$	6
Deferred tax asset — discontinued operations	—			128
Deferred tax liability— continuing operations	(65		)	(21		)
Net deferred tax (liability)/asset	$	(19	)	$	113

The primary driver for the decrease in the net deferred tax asset from $113 million as of December 31, 2017 to a net deferred tax liability of $19 million as of December 31, 2018 is the removal of NRG Yield, Inc.'s net deferred tax asset upon their sale in 2018. The 2017 beginning deferred balance included $128 million of NRG Yield Inc.'s net deferred tax assets, which were subsequently moved to discontinued operations prior to the sale.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of December 31, 2018 and 2017, NRG recorded a net deferred tax asset of $3.8 billion and $2.0 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 determination is based on the Company's assessment of cumulative and forecasted pretax book earnings and the future reversal of existing taxable temporary differences.

Based on the Company's assessment of positive and negative evidence, including available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $3.8 billion and $1.9 billion of tax assets as of December 31, 2018, and 2017, respectively, thus a valuation allowance has been recorded. The net deferred tax liability of $19 million as of December 31, 2018 is predominantly due to a foreign net deferred tax liability of $16 million and a net deferred tax liability for the state of Texas.

NOL carryforwards — At December 31, 2018, the Company had tax effected cumulative domestic NOLs consisting of carryforwards for federal income tax purposes of $2.2 billion and state of $379 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 2031. In addition, NRG has cumulative foreign NOL carryforwards of $62 million with no expiration date.

Valuation allowance — As of December 31, 2018, the Company's tax effected valuation allowance was $3.8 billion, consisting of domestic federal net deferred tax assets of approximately $3.3 billion, domestic state net deferred tax assets of $454 million, foreign NOL carryforwards of $62 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, 2018, NRG recorded a current tax payable of $3 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.

Uncertain tax benefits

NRG has identified uncertain tax benefits whose after-tax value is $26 million and $30 million, as of December 31, 2018 and 2017, for which NRG has recorded a non-current tax liability of $30 million and $33 million, respectively. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the year ended December 31, 2018, the Company recognized an expense of $1 million in interest. As of December 31, 2018 and 2017, NRG had cumulative interest and penalties related to these uncertain tax benefits of $4 million and $3 million, respectively.

Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia.

The Company is no longer subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 2010.

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



	As of December 31,
	2018			2017
	(In millions)
Balance as of January 1	$	30		$	34
Increase due to current year positions	4			4
Decrease due to prior year positions	—			(8		)
Decrease due to settlements and payments	(8		)	—
Uncertain tax benefits as of December 31	$	26		$	30

Stock-Based Compensation

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017, a total of 25,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP. There were 8,564,611 and 8,724,595 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 2018 and 2017, 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, 2018 and 2017, there were 520,182 and 1,369,880 shares of common stock remaining available for grants under the NRG GenOn LTIP, respectively.

Non-Qualified Stock Options

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 2018, 2017 or 2016.

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, 2017	1,285,858		$	25.49	3	$	6
Expired	(36,866	)	43.64
Exercised	(969,058	)	24.93
Outstanding at December 31, 2018	279,934		25.04		2	4
Exercisable at December 31, 2018	279,934		25.04		2	4

(a) As of December 31, 2018, 26,430 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,
	2018		2017		2016
	(In millions)
Total intrinsic value of options exercised	$	10	$	1	$	—
Cash received from options exercised	24		4		—

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

Restricted Stock Units

As of December 31, 2018, 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, 2017	2,377,813		$	14.63
Granted	447,309		28.90
Forfeited	(315,569	)	18.93
Vested	(1,051,471	)	17.67
Non-vested at December 31, 2018	1,458,082		16.16

(a) As of December 31, 2018, 7,319 RSUs granted to GenOn employees remain outstanding

The total fair value of RSUs vested during the years ended December 31, 2018, 2017, and 2016, was $42 million, $19 million, and $11 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2018, 2017, and 2016 was $28.90, $12.44, and $11.54, 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, 2017	427,148		$	21.54
Granted	61,645		33.43
Converted to Common Stock	(156,878	)	23.59
Outstanding at December 31, 2018	331,915		22.94

(a) There were no DSUs granted to GenOn employees and outstanding as of December 31, 2018 and 2017

The aggregate intrinsic values for DSUs outstanding as of December 31, 2018, 2017, and 2016 were approximately $13 million, $12 million, and $6 million, respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2018, 2017, and 2016 were $0 million, $4 million, and $1 million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2018, 2017, and 2016 was $33.43, $16.76, and $16.85, 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, 2018, 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, 2017	1,858,821		$	18.27
Granted	372,147		35.36
Forfeited	(134,473	)	22.26
Vested	(385,861	)	30.31
Non-vested at December 31, 2018	1,710,634		19.12

(a) There were no PSUs granted to GenOn employees and outstanding as of December 31, 2018

The weighted average grant date fair value of PSUs granted during the years ended December 31, 2018, 2017 and 2016, was $35.36, $15.91 and $14.73, 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:



	2018		2017		2016
	RPSUs		RPSUs		MSUs
Expected volatility	47.52	%	43.96	%	34.33	%
Expected term (in years)	3		3		3
Risk free rate	2.01	%	1.5	%	1.31	%

For the years ended December 31, 2018 and 2017, 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, 2018, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $19 million, $5 million, and $5 million for the years ended December 31, 2018, 2017, and 2016, respectively, are reflected as a reduction to additional paid-in capital on the Company's consolidated balance sheets and are reflected as operating activities on the Company's consolidated statements 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	2018			2017			2016			2018		2018
	(In millions, except weighted average data)
NQSOs^(a)	$	—		$	—		$	—		$	—	0.00
RSUs	12			15			12			9		0.89
DSUs	2			2			2			—		0.00
MSUs	4			5			2			—		0.03
RPSUs	7			3			—			10		1.32
PRSUs^(b)	16			13			4			14		1.17
Total^(c)	$	41		$	38		$	20		$	33
Tax detriment recognized	$	(4	)	$	(5	)	$	(4	)

(a) All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2018, 2017, and 2016

(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 compensation expense of $1 million, $6 million, and $4 million for each of the years ended December 31, 2018, 2017, and 2016, which was recorded in loss from discontinued operations in the Company's consolidated statements of operations

Related Party Transactions

12 Months Ended

Dec. 31, 2018

Related Party Transactions

The following table summarizes NRG's material related party transactions with third party affiliates:



	Year Ended December 31,
	2018		2017		2016
	(In millions)
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	3	$	3	$	2
GenConn	4		5		5
Ivanpah	20		—		—
Midway-Sunset	5		—		—
Total	$	32	$	8	$	7

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. NRG no longer has an ownership interest in GenConn as a result of the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform.

Ivanpah — NRG provides services to Ivanpah, an equity method investment as of May 1, 2018, under an operations and maintenance agreement. Fees for the services under this contract primarily include recovery of NRG's costs of operating the plant plus a profit margin.

Midway-Sunset — NRG provides services to Midway-Sunset, an equity method investment, under an operations and maintenance agreement. Fees for the 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 and an annual incentive bonus.

Services Agreement and Transition Services Agreement with GenOn

The Company provided 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 annual fees under the Services Agreement was approximately $193 million and management had concluded that this method of charging overhead costs was reasonable. In connection with the Restructuring Support Agreement in 2017, NRG agreed to provide shared services to GenOn under the Services Agreement for an adjusted annualized fee of $84 million.

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 provided the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments. GenOn provided notice to NRG of its intent to terminate the transition services agreement effective August 15, 2018 and in connection with the settlement agreement described in Note 3, Acquisitions, Discontinued Operations and Dispositions, all amounts owed and payable to NRG were settled against the $28 million credit provided for in the Restructuring Support Agreement. For the year ended December 31, 2018, NRG recorded approximately $53 million, under the transition services agreement against selling, general and administrative expenses post-Chapter 11 Filing. 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.

Credit Agreement with GenOn

NRG and GenOn were 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. As a result of the GenOn bankruptcy, no additional revolving loans or letters of credit were available to GenOn. As of December 31, 2017, $92 million of letters of credit were issued and outstanding. As a result of the GenOn Settlement, as further described in Note 3, Acquisitions, Discontinued Operations, and Dispositions, outstanding borrowings were repaid to NRG, except for certain LCs issued which are further discussed below. The facility was terminated on December 14, 2018.

On December 7, 2018, NRG, GenOn and REMA entered into an agreement to support the outstanding LCs from the intercompany revolving credit agreement previously issued. As of December 31, 2018, $30 million was outstanding. GenOn and REMA have provided support for these outstanding LCs through back-to-back letters of credit and cash collateral. The outstanding letters of credit will continue to accrue any contractual fees and expenses until they are terminated.

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, 2018, 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, 2018 and December 31, 2017, the Company had $4 million and $32 million, respectively, of cash collateral posted in support of energy risk management activities by GenOn.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

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 Midwest Generation the Company recorded in 2014 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. This accounting will change effective January 1, 2019 upon the adoption of ASU 2016-02 as discussed further in Note 2, Summary of Significant Accounting Policies - Recent Accounting Developments - Guidance Not Yet Adopted.

Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31, 2018 are as follows:



Period	(In millions)
2019	$	1
2020	1
2021	3
2022	6
2023	6
Thereafter	222
Total	$	239

Other Operating Leases

NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2036. 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 $66 million, $69 million, and $85 million for the years ended December 31, 2018, 2017, and 2016, respectively.

Future minimum lease commitments under operating leases for the years ending after December 31, 2018 are as follows:



Period^(a)	(In millions)
2019	$	60
2020	55
2021	43
2022	40
2023	39
Thereafter	95
Total	$	332

(a) Amounts in the table exclude future sublease income of $29 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, 2018, 2017, and 2016, the Company purchased $1.2 billion, $1.0 billion, and $1.1 billion, respectively, under such arrangements.

As of December 31, 2018, the Company's commitments under such outstanding agreements are as follows:



Period	(In millions)
2019	$	227
2020	156
2021	122
2022	74
2023	55
Thereafter	209
Total	$	843

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, 2018. Minimum purchase commitment obligations are as follows as of December 31, 2018:



Period	(In millions)
2019	$	30
2020	13
2021	12
2022	11
2023	1
Thereafter	1
Total ^(a)	$	68


(a)	As of December 31, 2018, the maximum remaining term under any individual purchased power contract is ten 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 EME (including Midwest Generation) acquisitions, 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, 2018, hedges under the first lien were out-of-the-money for NRG on a counterparty aggregate basis.

Lignite Contract with Texas Westmoreland Coal Co.

The Company's Limestone facility historically blended lignite obtained from the Jewett mine, which was operated by Texas Westmoreland Coal Co, or TWCC, and coal sourced from the Powder River Basin in Wyoming. 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 approximately $99 million on TWCC for the reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety bonds. Additionally, under the terms of the contract, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas.

On October 9, 2018, TWCC and certain of its affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code before the Bankruptcy Court for the Southern District of Texas. TWCC has obtained authorization from the Bankruptcy Court to continue to perform its obligations under its contract with the Company and to maintain surety bond programs throughout its operations. In addition, NRG has not received any indication from the Railroad Commission of Texas of an intent to draw on the surety bonds. TWCC has filed a plan of reorganization that, if confirmed, would provide for the assumption and/or assignment of the contract with NRG. Unless the Jewett mine and other related assets of TWCC are sold to another third party before the plan of reorganization is consummated, TWCC and/or its assets, including the Jewett mine and related agreements with NRG, will be owned upon the consummation of the plan by a new entity that is initially owned and controlled by certain holders of TWCC’s pre-bankruptcy funded indebtedness. The Bankruptcy Court is currently expected to consider confirmation of the plan in late February, unless adjourned to a later date. However, given the uncertainty involved in bankruptcy proceedings, it is uncertain whether these transactions will be consummated and whether and to what extent TWCC’s bankruptcy may, in the future, impact the reclamation costs incurred by NRG or the surety bonds.

Nuclear Insurance

STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Act. Effective September 10, 2018, the current liability limit per incident is $14.07 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, 2023. 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 $13.4 billion in funds available for public liability claims. The current maximum assessment per incident, per reactor, is approximately $138 million, taking into account a 5% adjustment for administrative fees, payable at approximately $21 million per year, per reactor. NRG would be responsible for 44% of the maximum assessment, or $9 million per year, per reactor, and a maximum of $61 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 $14 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, and European Mutual Association for Nuclear Insurance, or EMANI, both of which are industry mutual insurance companies, 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 non-nuclear event limit is expected to reduce to $1.0 billion effective April 1, 2019). The nuclear event limit remains 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 $3 million per unit up to a maximum of $274 million nuclear per unit and $184 million non-nuclear per unit, 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 $216 million nuclear and $144 million non-nuclear, and is subject to an eight-week waiting period. Under the terms of the NEIL and EMANI policies, member companies may be assessed up to ten and six times their annual premiums respectively if the NEIL or EMANI 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 and EMANI require that their 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 and EMANI to guarantee the Company's obligation; however note the NEIL aspect of 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. On March 27, 2018, ComEd filed a Motion to Compel Payments of Claims seeking $61 million related to asbestos liabilities. On April 25, 2018, NRG filed an Omnibus Objection to All Remaining Claims of ComEd and Exelon. A trial before the Bankruptcy Court to determine the amount of ComEd’s claims is currently scheduled for April 10, 2019.

California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC - On January 29, 2016, CDWR and SDG&E (plaintiffs) filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation (defendants). 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, plaintiffs filed a notice of appeal. On January 10, 2018, plaintiffs filed their opening appellate brief. Defendants filed their opposition brief on April 10, 2018. On May 30, 2018, plaintiffs filed their reply brief. The case is now waiting for the court of appeal to schedule oral argument.

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. After oral argument on April 24, 2018, the Appellate Division reversed the lower court on May 4, 2018, and ordered that the plaintiff must arbitrate their claims against NRG. On May 23, 2018, the plaintiff filed a petition for certification with the Supreme Court of New Jersey seeking to overturn the Appellate Division ruling. On January 25, 2019, the Supreme Court denied plaintiff’s petition for certification.

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 its answer and affirmative defenses on November 17, 2017. On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.

GenOn Chapter 11 Cases - On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On December 12, 2017, the Bankruptcy Court entered an order confirming GenOn's Chapter 11 plan, which provides for, among other things, GenOn’s transition to a standalone enterprise. GenOn's Chapter 11 plan became effective on December 14, 2018.

Regulatory Matters	12 Months Ended
Regulatory Matters	Dec. 31, 2018
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. Zero-Emission Credits for Nuclear Plants in Illinois and New York - 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 two Exelon-owned nuclear power plants in Illinois. That same year, the NYSPSC issued its Clean Energy Standard, or CES, which provides 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 New York. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. NRG, along with other companies, filed complaints in the federal courts of Illinois and New York alleging that these state programs are preempted by federal law and in violation of the dormant commerce clause. These cases have proceeded through the federal district court as well as the federal appellate court in Illinois and New York, respectively. On January 7, 2019, NRG and its trade association filed a Petition for Writ of Certiorari with the United States Supreme Court in both cases. 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. South Central - On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO and PJM markets. It required NRG to retain communications related to multiple generating units in the South Central region. Since sending the notice, FERC has been investigating potential violations of MISO rules involving bidding for the Big Cajun 2 facility, as well as other aspects of NRG’s operations in MISO. FERC has the authority to require disgorgement of profits and to impose penalties and NRG retains any liability following the sale of the South Central Portfolio. We expect a preliminary finding from FERC by the second quarter of 2019. ISO-NE - On February 5, 2019, FERC has informed the Company that it has made a preliminary finding that the Company violated FERC's market behavior rules in connection with offers made into the ISO-NE Forward Capacity Auction in 2016. The Company understands that FERC is concerned that the Company was inaccurate in its communications with the Market Monitor regarding the costs and risks associated with operating certain units in the forward timeframe. Ultimately, the Company opted to withdraw the relevant bids prior to the auction in 2016. The Company will be engaging in discussions with FERC regarding this matter.

Environmental Matters	12 Months Ended
Environmental Matters	Dec. 31, 2018
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. Air On August 31, 2018, EPA proposed replacing the Clean Power Plan (CPP) rule, which sought to broadly regulate CO₂ emissions from the power sector, with the Affordable Clean Energy (ACE) rule, which if finalized, would require states to develop plans to seek heat rate improvements from coal-fired EGUs. The Company believes that the ACE rule replacing the CPP rule would on balance be positive for its generation fleet. 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. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule. 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 Once Through Cooling Regulation — 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, the Company anticipates the cost of complying with these requirements to be immaterial. 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. In 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. Accordingly, we anticipate that the EPA will promulgate new regulations to address these issues (including compliance deadlines) as it reconsiders other aspects of the existing rule. The EPA has stated that it intends to further revise the rule. The Company will provide estimates of the cost of compliance after the rule is revised. For further discussion of these matters, refer to Note 21, Commitments and Contingencies.

Cash Flow Information

12 Months Ended

Dec. 31, 2018

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,
	2018		2017		2016
	(In millions)
Interest paid, net of amount capitalized	$	436	$	543	$	606
Income taxes paid, net of refunds	9		9		14
Non-cash investing and financing activities:
Additions to fixed assets for accrued capital expenditures	20		19		9

Guarantees

12 Months Ended

Dec. 31, 2018

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,
	2018
Guarantees	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2017 Total
	(In millions)
Letters of credit and surety bonds^(a)(b)	$	1,138	$	79	$	—	$	36	$	1,253	$	1,003
Asset sales guarantee obligations	—		4		257		532		793		312
Other guarantees	—		105		—		616		721		645
Total guarantees	$	1,138	$	188	$	257	$	1,184	$	2,767	$	1,960


(a)	As of December 31, 2017 excludes $92 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn


(b)	December 31, 2018 includes $32 million of letter of credit and surety bonds for the benefit of GenOn where NRG holds cash or letter of credit to back stop the liability

Letters of credit and surety bonds — As of December 31, 2018, NRG and its consolidated subsidiaries were contingently obligated for a total of $1.3 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, except as described in Note 3, Acquisitions, Discontinued Operations and Dispositions.

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

12 Months Ended

Dec. 31, 2018

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, 2018	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	%	$	382	$	(185	)	$	5
Cedar Bayou Unit 4, Baytown, TX	50.00	%	215		(84		)	8

Unaudited Quarterly Financial Data

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Unaudited Quarterly Financial Data

Refer to Note 3, Acquisitions, Discontinued Operations and Dispositions, and Note 9, 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
	2018
	December 31			September 30			June 30		March 31
	(In millions, except per share data)
Operating revenues	$	1,992		$	2,960		$	2,461	$	2,065
Operating income	49			398			174		361
Net (loss)/income from continuing operations	(93		)	288			27		238
Income/(loss) from discontinued operations	80			(336		)	69		(5		)
Net (loss)/income	(13		)	(48		)	96		233
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	(2		)	24			24		(46		)
(Loss)/income available to Common Stockholders	$	(11	)	$	(72	)	$	72	$	279
Weighted average number of common shares outstanding — basic	289			299			310		318
Income/(loss) from discontinued operations per weighted average common share — basic	$	0.28		$	(1.12	)	$	0.22	$	(0.02	)
Net (loss)/income per weighted average common share — basic	$	(0.04	)	$	(0.24	)	$	0.23	$	0.88
Weighted average number of common shares outstanding — diluted	289			299			314		322
Income/(loss) from discontinued operations per weighted average common share — diluted	$	0.28		$	(1.12	)	$	0.22	$	(0.02	)
Net (loss)/income per weighted average common share — diluted	$	(0.04	)	$	(0.24	)	$	0.23	$	0.87



	Quarter Ended
	2017
	December 31			September 30			June 30			March 31
	(In millions, except per share data)
Operating revenues	$	2,154		$	2,618		$	2,281		$	2,021
Operating (loss)/income	(1,200		)	275			214			(30		)
Net (loss)/income from continuing operations	(1,390		)	163			60			(178		)
(Loss)/income from discontinued operations	(265		)	—			(702		)	(25		)
Net (loss)/income	(1,655		)	163			(642		)	(203		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(120		)	(8		)	(16		)	(40		)
(Loss)/income available to Common Stockholders	$	(1,535	)	$	171		$	(626	)	$	(163	)
Weighted average number of common shares outstanding — basic	317			317			316			316
(Loss)/income from discontinued operations per weighted average common share — basic	$	(0.84	)	$	—		$	(2.22	)	$	(0.08	)
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
(Loss)/income from discontinued operations per weighted average common share — diluted	$	(0.84	)	$	—		$	(2.22	)	$	(0.08	)
Net (loss)/income per weighted average common share — diluted	$	(4.84	)	$	0.53		$	(1.98	)	$	(0.52	)

Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2018

Condensed Financial Information Disclosure [Abstract]

Condensed Consolidating Financial Information

As of December 31, 2018, the Company had outstanding $4.4 billion of Senior Notes due 2022 to 2048, as shown in Note 11, 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.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2018:



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

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 11, Debt and Capital Leases, to the consolidated financial statements. For a discussion of NRG Energy, Inc.'s contingencies, see Note 21, Commitments and Contingencies, to the consolidated financial statements. For a discussion of NRG Energy, Inc.'s guarantees, see Note 25, Guarantees, to the consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2018



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	8,119		$	1,385		$	—		$	(26	)	$	9,478
Operating Costs and Expenses
Cost of operations	6,147			959			28			(26		)	7,108
Depreciation and amortization	238			150			33			—			421
Impairment losses	6			93			—			—			99
Selling, general and administrative	462			63			348			(74		)	799
Reorganization costs	4			—			86			—			90
Development costs	—			1			11			(1		)	11
Total operating costs and expenses	6,857			1,266			506			(101		)	8,528
Gain on sale of assets	4			28			—			—			32
Operating Income/(Loss)	1,266			147			(506		)	75			982
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	23			—			1,291			(1,314		)	—
Equity in earnings/(losses) of unconsolidated affiliates	—			10			(1		)	—			9
Impairment losses on investments	—			(15		)	—			—			(15		)
Other income/(expense), net	32			(13		)	(1		)	—			18
Loss on debt extinguishment, net	—			—			(44		)	—			(44		)
Interest expense	(14		)	(49		)	(420		)	—			(483		)
Total other income/(expense)	41			(67		)	825			(1,314		)	(515		)
Income from Continuing Operations Before Income Taxes	1,307			80			319			(1,239		)	467
Income tax expense/(benefit)	372			19			(384		)	—			7
Income from Continuing Operations	935			61			703			(1,239		)	460
Income/(Loss) from Discontinued Operations, net of income tax	62			75			(329		)	—			(192		)
Net Income	997			136			374			(1,239		)	268
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	—			(181		)	106			75			—
Net Income Attributable to NRG Energy, Inc.	$	997		$	317		$	268		$	(1,314	)	$	268


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the Year Ended December 31, 2018



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income	$	997		$	136		$	374		$	(1,239	)	$	268
Other Comprehensive Income, net of tax
Unrealized gain on derivatives, net	—			29			9			(15		)	23
Foreign currency translation adjustments, net	(10		)	(10		)	(13		)	22			(11		)
Available-for-sale securities, net	—			—			1			—			1
Defined benefit plan, net	(9		)	—			(35		)	9			(35		)
Other comprehensive (loss)/income	(19		)	19			(38		)	16			(22		)
Comprehensive Income	978			155			336			(1,223		)	246
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	—			(166		)	104			76			14
Comprehensive Income Attributable to NRG Energy, Inc.	$	978		$	321		$	232		$	(1,299	)	$	232


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2018



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc.			Eliminations^(a)			Consolidated Balance
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	55	$	28		$	480		$	—		$	563
Funds deposited by counterparties	33		—			—			—			33
Restricted cash	7		10			—			—			17
Accounts receivable - trade	894		82			43			—			1,019
Inventory	278		134			—			—			412
Derivative instruments	779		50			16			(81		)	764
Cash collateral posted in support of energy risk management activities	275		12			—			—			287
Accounts receivable - affiliate	460		33			266			(754		)	5
Prepayments and other current assets	180		32			90			—			302
Current assets - held-for-sale	—		1			—			—			1
Current assets - discontinued operations	177		20			—			—			197
Total current assets	3,138		402			895			(835		)	3,600
Property, plant and equipment, net	1,938		957			153			—			3,048
Other Assets
Investment in subsidiaries	446		—			4,707			(5,153		)	—
Equity investments in affiliates	—		412			—			—			412
Goodwill	359		214			—			—			573
Intangible assets, net	422		169			—			—			591
Nuclear decommissioning trust fund	663		—			—			—			663
Derivative instruments	296		4			22			(5		)	317
Deferred income taxes	6		(143		)	183			—			46
Other non-current assets	133		71			97			(12		)	289
Non-current assets - held-for-sale	—		77			—			—			77
Non-current assets - discontinued operations	405		607			—			—			1,012
Total other assets	2,730		1,411			5,009			(5,170		)	3,980
Total Assets	$	7,806	$	2,770		$	6,057		$	(6,005	)	$	10,628
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	55		$	17		$	—		$	72
Accounts payable	693		64			105			—			862
Accounts payable - affiliate	675		(249		)	329			(754		)	1
Derivative instruments	713		41			—			(81		)	673
Cash collateral received in support of energy risk management activities	33		—			—			—			33
Accrued expenses and other current liabilities	291		36			353			—			680
Current liabilities - held-for-sale	—		5			—			—			5
Current liabilities - discontinued operations	24		48			—			—			72
Total current liabilities	2,429		—			804			(835		)	2,398
Other Liabilities
Long-term debt and capital leases	244		192			6,025			(12		)	6,449
Nuclear decommissioning reserve	282		—			—			—			282
Nuclear decommissioning trust liability	371		—			—			—			371
Postretirement and other benefit obligations	114		1			320			—			435
Derivative instruments	306		3			—			(5		)	304
Deferred income taxes	112		61			(108		)	—			65
Out-of-market contracts, net	—		121			—			—			121
Other non-current liabilities	288		198			232			—			718
Non-current liabilities - held-for-sale	—		65			—			—			65
Non-current liabilities - discontinued operations	58		577			—			—			635
Total non-current liabilities	1,775		1,218			6,469			(17		)	9,445
Total Liabilities	4,204		1,218			7,273			(852		)	11,843
Redeemable noncontrolling interest in subsidiaries	—		19			—			—			19
Stockholders' Equity	3,602		1,533			(1,216		)	(5,153		)	(1,234		)
Total Liabilities and Stockholders' Equity	$	7,806	$	2,770		$	6,057		$	(6,005	)	$	10,628


(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, 2018



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net income	$	997		$	136		$	374		$	(1,239	)	$	268
Income/(loss) from discontinued operations	62			75			(329		)	—			(192		)
Net income from continuing operations	935			61			703			(1,239		)	460
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			47			(1		)	—			46
Depreciation, amortization and accretion	266			160			33			—			459
Provision for bad debts	79			6			—			—			85
Amortization of nuclear fuel	48			—			—			—			48
Amortization of financing costs and debt discount/premiums	—			6			23			—			29
Adjustment for debt extinguishment	—			—			44			—			44
Amortization of intangibles and out-of-market contracts	36			9			—			—			45
Amortization of unearned equity compensation	—			—			25			—			25
Net (gain)/loss on sale of assets and equity/cost method investments	(30		)	(20		)	1			—			(49		)
Impairment losses	5			109			—			—			114
Changes in derivative instruments	25			15			11			(14		)	37
Changes in deferred income taxes and liability for uncertain tax benefits	372			5			(372		)	—			5
Changes in collateral deposits in support of energy risk management activities	(94		)	(11		)	—			—			(105		)
Changes in nuclear decommissioning trust liability	60			—			—			—			60
GenOn settlement, net of insurance proceeds	—			—			(63		)	—			(63		)
Net loss on deconsolidation of Agua Caliente and Ivanpah projects	—			13			—			—			13
Changes in other working capital	311			(193		)	(1,621		)	1,253			(250		)
Cash provided/(used) by continuing operations	2,013			207			(1,217		)	—			1,003
Cash provided by discontinued operations	89			285			—			—			374
Net Cash Provided/(Used) by Operating Activities	2,102			492			(1,217		)	—			1,377
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(40		)	(203		)	—			—			(243		)
Capital expenditures	(192		)	(151		)	(45		)	—			(388		)
Net proceeds from sale of emission allowances	19			—			—			—			19
Investments in nuclear decommissioning trust fund securities	(572		)	—			—			—			(572		)
Proceeds from sales of nuclear decommissioning trust fund securities	513			—			—			—			513
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	14			8			1,542			—			1,564
Deconsolidation of Agua Caliente and Ivanpah projects	—			(268		)	—			—			(268		)
Changes in investments in unconsolidated affiliates	—			(39		)	—			—			(39		)
Net (contributions to)/distributions from discontinued operations	—			(60		)	—			—			(60		)
Other	—			—			(6		)	—			(6		)
Cash (used)/provided by continuing operations	(258		)	(713		)	1,491			—			520
Cash used by discontinued operations	—			(725		)	—			—			(725		)
Net Cash (Used)/Provided by Investing Activities	(258		)	(1,438		)	1,491			—			(205		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(1,701		)	113			1,588			—			—
Payments of dividends to preferred and common stockholders	—			—			(37		)	—			(37		)
Payments for treasury stock	—			—			(1,250		)	—			(1,250		)
Payments for debt extinguishment costs	—			—			(32		)	—			(32		)
Net distributions to noncontrolling interests from subsidiaries	—			(16		)	—			—			(16		)
Proceeds from issuance of common stock	—			—			21			—			21
Proceeds from issuance of long-term debt	—			163			937			—			1,100
Payments of debt issuance costs	—			—			(19		)	—			(19		)
Payments for short and long-term debt	—			(138		)	(1,596		)	—			(1,734		)
Receivable from affiliate	—			—			(26		)	—			(26		)
Other	—			(4		)	—			—			(4		)
Cash (used)/provided by continuing operations	(1,701		)	118			(414		)	—			(1,997		)
Cash provided by discontinued operations	—			471			—			—			471
Net Cash (Used)/Provided by Financing Activities	(1,701		)	589			(414		)	—			(1,526		)
Effect of exchange rate changes on cash and cash equivalents	—			1			—			—			1
Change in cash from discontinued operations	89			31			—			—			120
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	54			(387		)	(140		)	—			(473		)
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	41			425			620			—			1,086
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	95		$	38		$	480		$	—		$	613


(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, 2017



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,818		$	1,304		$	—		$	(48	)	$	9,074
Operating Costs and Expenses
Cost of operations	5,998			862			72			(46		)	6,886
Depreciation and amortization	343			221			32			—			596
Impairment losses	1,346			188			—			—			1,534
Selling, general and administrative	410			64			364			(2		)	836
Reorganization costs	6			—			38			—			44
Development costs	—			4			18			—			22
Total operating costs and expenses	8,103			1,339			524			(48		)	9,918
Other income - affiliate	—			—			87			—			87
Gain on sale of assets	4			12			—			—			16
Operating Loss	(281		)	(23		)	(437		)	—			(741		)
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	18			—			28			(46		)	—
Equity in losses of unconsolidated affiliates	—			(10		)	(4		)	—			(14		)
Impairment losses on investments	—			(75		)	(4		)	—			(79		)
Other income, net	9			14			28			—			51
Loss on debt extinguishment, net	—			—			(49		)	—			(49		)
Interest expense	(14		)	(91		)	(452		)	—			(557		)
Total other income/(expense)	13			(162		)	(453		)	(46		)	(648		)
Loss from Continuing Operations Before Income Taxes	(268		)	(185		)	(890		)	(46		)	(1,389		)
Income tax (benefit)/expense	(598		)	(62		)	616			—			(44		)
Income/(Loss) from Continuing Operations	330			(123		)	(1,506		)	(46		)	(1,345		)
Income/(Loss) from Discontinued Operations, net of income tax	91			(420		)	(663		)	—			(992		)
Net Income/(Loss)	421			(543		)	(2,169		)	(46		)	(2,337		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			(168		)	(16		)	—			(184		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	421		$	(375	)	$	(2,153	)	$	(46	)	$	(2,153	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Year Ended December 31, 2017



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income/(Loss)	$	421		$	(543	)	$	(2,169	)	$	(46	)	$	(2,337	)
Other Comprehensive Income/(Loss), 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	(13		)	30			41			(12		)	46
Other comprehensive (loss)/income	(6		)	50			58			(39		)	63
Comprehensive Income/(Loss)	415			(493		)	(2,111		)	(85		)	(2,274		)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			(103		)	(16		)	(60		)	(179		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	415		$	(390	)	$	(2,095	)	$	(25	)	$	(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	$	—	$	150		$	620		$	—		$	770
Funds deposited by counterparties	37		—			—			—			37
Restricted cash	4		275			—			—			279
Accounts receivable - trade	852		44			4			—			900
Inventory	307		146			—			—			453
Derivative instruments	647		24			10			(57		)	624
Cash collateral posted in support of energy risk management activities	170		1			—			—			171
Accounts receivable - affiliate	685		183			(154		)	(534		)	180
Prepayments and other current assets	106		30			27			—			163
Current assets - held-for-sale	8		108			—			—			116
Current assets - discontinued operations	89		655			—			—			744
Total current assets	2,905		1,616			507			(591		)	4,437
Property, plant and equipment, net	2,052		3,689			237			(4		)	5,974
Other Assets
Investment in subsidiaries	266		—			8,234			(8,500		)	—
Equity investments in affiliates	—		181			1			—			182
Goodwill	359		180			—			—			539
Intangible assets, net	455		55			—			(3		)	507
Nuclear decommissioning trust fund	692		—			—			—			692
Derivative instruments	126		2			31			—			159
Deferred income taxes	377		(135		)	(236		)	—			6
Other non-current assets	64		126			120			—			310
Non-current assets - held for sale	—		43			—			—			43
Non-current assets - discontinued operations	456		10,072			—			(22		)	10,506
Total other assets	2,795		10,524			8,150			(8,525		)	12,944
Total Assets	$	7,752	$	15,829		$	8,894		$	(9,120	)	$	23,355
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	183		$	21		$	—		$	204
Accounts payable	582		47			55			—			684
Accounts payable - affiliate	725		(310		)	176			(534		)	57
Derivative instruments	556		38			—			(57		)	537
Cash collateral received in support of energy risk management activities	37		—			—			—			37
Accrued expenses and other current liabilities	313		67			376			—			756
Accrued expenses and other current liabilities - affiliate	—		—			161			—			161
Current liabilities - held-for-sale	—		72			—			—			72
Current liabilities - discontinued operations	34		807			5			—			846
Total current liabilities	2,247		904			794			(591		)	3,354
Other Liabilities
Long-term debt and capital leases	244		2,197			6,739			—			9,180
Nuclear decommissioning reserve	269		—			—			—			269
Nuclear decommissioning trust liability	415		—			—			—			415
Postretirement and other benefit obligations	118		1			339			—			458
Derivative instruments	136		7			—			—			143
Deferred income taxes	112		64			(155		)	—			21
Out-of-market contracts, net	—		129			—			—			129
Other non-current liabilities	284		198			52			—			534
Non-current liabilities - held-for-sale	—		8			—			—			8
Non-current liabilities - discontinued operations	73		6,725			—			—			6,798
Total non-current liabilities	1,651		9,329			6,975			—			17,955
Total Liabilities	3,898		10,233			7,769			(591		)	21,309
Redeemable noncontrolling interest in subsidiaries	—		78			—			—			78
Stockholders' Equity	3,854		5,518			1,125			(8,529		)	1,968
Total Liabilities and Stockholders' Equity	$	7,752	$	15,829		$	8,894		$	(9,120	)	$	23,355


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

NERGY, 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
	(In millions)
Cash Flows from Operating Activities
Net income/(loss)	$	421		$	(543	)	$	(2,169	)	$	(46	)	$	(2,337	)
Income/(loss) from discontinued operations	91			(420		)	(663		)	—			(992		)
Net income/(loss) from continuing operations	330			(123		)	(1,506		)	(46		)	(1,345		)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			12			90			—			102
Depreciation, amortization and accretion	343			221			32			—			596
Provision for bad debts	56			—			12			—			68
Amortization of nuclear fuel	51			—			—			—			51
Amortization of financing costs and debt discount/premiums	—			13			16			—			29
Adjustment for debt extinguishment	—			—			49			—			49
Amortization of intangibles and out-of-market contracts	42			12			—			—			54
Amortization of unearned equity compensation	—			—			35			—			35
Net loss/(gain) on sale of assets and equity/cost method investments	2			(11		)	—			—			(9		)
Impairment losses	1,346			264			4			—			1,614
Changes in derivative instruments	(214		)	50			(4		)	(2		)	(170		)
Changes in deferred income taxes and liability for uncertain tax benefits	(300		)	(9		)	322			—			13
Changes in collateral deposits in support of energy risk management activities	(98		)	18			—			—			(80		)
Changes in nuclear decommissioning trust liability	11			—			—			—			11
Changes in other working capital	82			(354		)	62			48			(162		)
Cash provided/(used) by continuing operations	1,651			93			(888		)	—			856
Cash provided by discontinued operations	116			638			—			—			754
Net Cash Provided/(Used) by Operating Activities	1,767			731			(888		)	—			1,610
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(14		)	—			—			—			(14		)
Capital expenditures	(180		)	(43		)	(31		)	—			(254		)
Proceeds from renewable energy grants	—			8			—			—			8
Net 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 of cash disposed and sale of discontinued operations, net of fees	33			54			343			—			430
Changes in investments in unconsolidated affiliates	—			(57		)	—			—			(57		)
Net distributions from discontinued operations	—			—			150			—			150
Other	18			4			—			—			22
Cash (used)/provided by continuing operations	(88		)	(34		)	462			—			340
Cash used by discontinued operations	(13		)	(966		)	—			—			(979		)
Net Cash (Used)/Provided by Investing Activities	(101		)	(1,000		)	462			—			(639		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(1,525		)	(39		)	1,564			—			—
Payment of dividends to preferred and common stockholders	—			—			(38		)	—			(38		)
Payments for debt extinguishment costs	—			—			(42		)	—			(42		)
Net distributions to noncontrolling interests from subsidiaries	—			(30		)	—			—			(30		)
Payments for issuance of common stock	—			—			(2		)	—			(2		)
Proceeds from issuance of long-term debt	—			94			1,084			—			1,178
Payment of debt issuance costs	—			(2		)	(16		)	—			(18		)
Payments for short and long-term debt	—			(183		)	(1,701		)	—			(1,884		)
Receivable from affiliate	—			—			(125		)	—			(125		)
Other	—			(8		)	—			—			(8		)
Cash (used)/provided by continuing operations	(1,525		)	(168		)	724			—			(969		)
Cash used by discontinued operations	(109		)	(60		)	—			—			(169		)
Net Cash (Used)/Provided by Financing Activities	(1,634		)	(228		)	724			—			(1,138		)
Effect of exchange rate changes on cash and cash equivalents	—			(1		)	—			—			(1		)
Change in cash from discontinued operations	(6		)	(388		)	—			—			(394		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	38			(110		)	298			—			226
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	3			535			322			—			860
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	41		$	425		$	620		$	—		$	1,086

(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.			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,539		$	1,450		$	—		$	(74	)	$	8,915
Operating Costs and Expenses
Cost of operations	5,581			1,116			59			(80		)	6,676
Depreciation and amortization	500			230			26			—			756
Impairment losses	370			113			—			—			483
Selling, general and administrative	430			144			458			—			1,032
Development costs	—			18			30			—			48
Total operating costs and expenses	6,881			1,621			573			(80		)	8,995
Other income - affiliate	—			—			193			—			193
Loss on sale of assets	(1		)	—			(79		)	—			(80		)
Operating Income/(Loss)	657			(171		)	(459		)	6			33
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries	(50		)	—			374			(324		)	—
Equity in earnings/(losses) of unconsolidated affiliates	5			(9		)	(4		)	(10		)	(18		)
Impairment losses on investments	—			(252		)	(16		)	—			(268		)
Other income, net	5			15			27			—			47
Net loss on debt extinguishment	—			(4		)	(138		)	—			(142		)
Interest expense	(15		)	(85		)	(483		)	—			(583		)
Total other expense	(55		)	(335		)	(240		)	(334		)	(964		)
Income/(Loss) from Continuing Operations Before Income Taxes	602			(506		)	(699		)	(328		)	(931		)
Income tax (benefit)/expense	(1		)	28			(2		)	—			25
Income/(Loss) from Continuing Operations	603			(534		)	(697		)	(328		)	(956		)
Income/(Loss) from Discontinued Operations, net of income tax	86			—			(21		)	—			65
Net Income/(Loss)	689			(534		)	(718		)	(328		)	(891		)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	—			(169		)	56			(4		)	(117		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	689		$	(365	)	$	(774	)	$	(324	)	$	(774	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Year Ended December 31, 2016



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income/(Loss)	$	689		$	(534	)	$	(718	)	$	(328	)	$	(891	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net	—			32			89			(86		)	35
Foreign currency translation adjustments, net	(1		)	(1		)	(1		)	2			(1		)
Available-for-sale securities, net	—			—			1			—			1
Defined benefit plan, net	44			(13		)	(51		)	23			3
Other comprehensive income	43			18			38			(61		)	38
Comprehensive Income/(Loss)	732			(516		)	(680		)	(389		)	(853		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest	—			(103		)	56			(70		)	(117		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	732			(413		)	(736		)	(319		)	(736		)
Dividends for preferred shares	—			—			5			—			5
Gain on redemption of preferred shares	—			—			(78		)	—			(78		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	732		$	(413	)	$	(663	)	$	(319	)	$	(663	)


(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)	$	689		$	(534	)	$	(718	)	$	(328	)	$	(891	)
Income/(loss) from discontinued operations	86			—			(21		)	—			65
Net income/(loss) from continuing operations	603			(534		)	(697		)	(328		)	(956		)
Adjustments to reconcile net income/(loss) to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	(5		)	(14		)	86			—			67
Depreciation, amortization and accretion	508			238			26			—			772
Provision for bad debts	42			3			—			—			45
Amortization of nuclear fuel	49			—			—			—			49
Amortization of financing costs and debt discount/premiums	—			13			20			—			33
Adjustment for debt extinguishment	—			4			138			—			142
Amortization of intangibles and out-of-market contracts	56			12			—			—			68
Amortization of unearned equity compensation	—			—			10			—			10
Net loss on sale of assets and equity/cost method investments	70			—			69			—			139
Impairment losses	370			365			16			—			751
Changes in derivative instruments	28			21			(36		)	3			16
Changes in deferred income taxes and liability for uncertain tax benefits	(1		)	49			(60		)	—			(12		)
Changes in collateral deposits in support of energy risk management activities	384			12			—			—			396
Changes in nuclear decommissioning trust liability	41			—			—			—			41
Changes in other working capital	(139		)	(54		)	(256		)	325			(124		)
Cash provided/(used) by continuing operations	2,006			115			(684		)	—			1,437
Cash provided by discontinued operations	174			297			—			—			471
Net Cash Provided/(Used) by Operating Activities	2,180			412			(684		)	—			1,908
Cash Flows from Investing Activities
Acquisition of business, net of cash acquired	—			—			—			—			—
Capital expenditures	(172		)	(326		)	(46		)	—			(544		)
Proceeds from renewable energy grants	—			36			—			—			36
Net purchases of emission allowances	(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 of cash disposed and sale of discontinued operations, net of fees	—			56			185			—			241
Changes in investments in unconsolidated affiliates	—			(33		)	—			—			(33		)
Net distributions to discontinued operations	—			—			(58		)	—			(58		)
Other	27			4			—			—			31
Cash (used)/provided by continuing operations	(187		)	(263		)	81			—			(369		)
Cash used by discontinued operations	(9		)	(379		)	—			—			(388		)
Net Cash (Used)/Provided by Investing Activities	(196		)	(642		)	81			—			(757		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(1,856		)	375			1,481			—			—
Payment of dividends to preferred and common stockholders	—			—			(76		)	—			(76		)
Payment for preferred shares	—			—			(226		)	—			(226		)
Payments for debt extinguishment costs	—			—			(121		)	—			(121		)
Net distributions to noncontrolling interest from subsidiaries	—			(27		)	—			—			(27		)
Proceeds from issuance of common stock	—			—			1			—			1
Proceeds from issuance of long-term debt	—			271			4,141			—			4,412
Payments of debt issuance costs	—			—			(61		)	—			(61		)
Payments for short and long-term debt	(2		)	(221		)	(4,923		)	—			(5,146		)
Other	(3		)	(4		)	—			—			(7		)
Cash (used)/provided by continuing operations	(1,861		)	394			216			—			(1,251		)
Cash (used)/provided by discontinued operations	(163		)	646			—			—			483
Net Cash (Used)/Provided by Financing Activities	(2,024		)	1,040			216			—			(768		)
Effect of exchange rate changes on cash and cash equivalents	—			1			—			—			1
Change in cash from discontinued operations	2			564			—			—			566
Net (Decrease)/Increase in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	(42		)	247			(387		)	—			(182		)
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	45			288			709			—			1,042
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	3		$	535		$	322		$	—		$	860

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

VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Dec. 31, 2018

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2018, 2017, and 2016



	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, 2018	$	28	$	83		$	—		$	(79	)	^(a)	$	32
Year Ended December 31, 2017	28		57			—			(57		)	^(a)	28
Year Ended December 31, 2016	21		55			—			(48		)	^(a)	28
Income tax valuation allowance, deducted from deferred tax assets
Year Ended December 31, 2018	$	1,863	$	1,934		$	(128	)	$	125		^(b)	$	3,794
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


(a)	Represents principally net amounts charged as uncollectible


(b)	Represents removal of NRG Yield, Inc. and its Renewables Platform due to their sale on August 31, 2018


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

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

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,
	2018		2017		2016
	(In millions)
Cash and cash equivalents	$	563	$	770	$	591
Funds deposited by counterparties	33		37		2
Restricted cash	17		279		267
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$	613	$	1,086	$	860

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

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

Contract Amortization

Lease Revenue

Revenue Recognition

Revenue from Contracts with Customers

Retail Revenues

Energy Revenue

Capacity Revenue

Capacity revenue contracts mainly consist of:

Renewable Energy Credits

Sale of Emission Allowances

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

Redeemable Noncontrolling Interest

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 severance and contract modifications.

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 2018

Recent Accounting Developments - Guidance Not Yet Adopted

Nuclear Decommissioning Policy

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Net Income/(Loss) Attributable to Continuing and Discontinued Operations

The following table reflects the net income/(loss) attributable to NRG Energy, Inc. after removing the net loss attributable to the noncontrolling interest and redeemable noncontrolling interest:



	Year Ended December 31,
	2018			2017			2016
	(In millions)
Income/(loss) from continuing operations, net of income tax	$	465		$	(977	)	$	(733	)
Loss from discontinued operations, net of income tax	(197		)	(1,176		)	(41		)
Net income/(loss) attributable to NRG Energy, Inc. stockholders	$	268		$	(2,153	)	(774		)

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



	Year Ended December 31,
	2018		2017		2016
	(In millions)
Cash and cash equivalents	$	563	$	770	$	591
Funds deposited by counterparties	33		37		2
Restricted cash	17		279		267
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$	613	$	1,086	$	860

Disaggregation of Revenue

The following table represents the Company’s disaggregation of revenue from contracts with customers for the year ended December 31, 2018, along with the reportable segment for each category:



	For the Year Ended December 31, 2018
				Generation
(In millions)	Retail			Texas			East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue^(a)	$	—		$	1,585		$	1,092		$	2,677		$	(1,129	)	$	1,548
Capacity revenue^(a)	—			1			669			670			—			670
Retail revenue
Mass customers	5,618			—			—			—			(5		)	5,613
Business Solutions customers	1,492			—			—			—			—			1,492
Total retail revenue	7,110			—			—			—			(5		)	7,105
Mark-to-market for economic hedging activities^(b)	(7		)	(174		)	(28		)	(202		)	79			(130		)
Other revenue^(a)(c)	—			84			203			287			(2		)	285
Total operating revenue	7,103			1,496			1,936			3,432			(1,057		)	9,478
Less: Lease revenue	13			—			8			8			—			21
Less: Derivative revenue	(7		)	2,160			193			2,353			(1,037		)	1,309
Total revenue from contracts with customers	$	7,097		$	(664	)	$	1,735		$	1,071		$	(20	)	$	8,148
(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
	Retail			Texas			East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	2,332		$	69		$	2,401		$	(1,117	)	$	1,284
Capacity revenue	—			—			138			138			—			138
Other revenue	—			2			14			16			—			16

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

(c) Included in other revenue is lease revenue of $17 million and $5 million for Retail and East/West/Other, respectively

Contract Assets and Liabilities

The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31, 2018:




	(In millions)
Deferred customer acquisition costs	$	111

Accounts receivable, net - Contracts with customers	1,002
Accounts receivable, net - Derivative instruments	20
Total accounts receivable, net	$	1,022

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	392
Deferred revenues	$	67

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, 2018, 2017, and 2016.



	(In millions)
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
Distributions to redeemable noncontrolling interest	(3		)
Contributions from redeemable noncontrolling interest	26
Non-cash adjustments to redeemable noncontrolling interest	(8		)
Net income attributable to redeemable noncontrolling interest - continuing operations	1
Net loss attributable to redeemable noncontrolling interest - discontinued operations	(27		)
Sale of NRG Yield and the Renewables Platform^(a)	(48		)
Balance as of December 31, 2018	$	19

Acquisitions, Discontinued Operations and Dispositions (Tables)

12 Months Ended

Dec. 31, 2018

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Allocation of Purchase Price

The acquisition increased NRG's retail portfolio by approximately 300,000 customers. The purchase price was allocated as follows:



	(In millions)
Net current and non-current working capital	$	46
Other intangible assets	133
Goodwill	34
XOOM Purchase Price	$	213

Summary of Results of Discontinued Operations

The following table summarizes the major classes of assets and liabilities classified as discontinued operations of South Central as follows:



(In millions)	December 31, 2018		December 31, 2017
Cash and cash equivalents	$	89	$	(3	)
Accounts receivable, net	49		61
Inventory	35		33
Other current assets	5		—
Current assets - discontinued operations	178		91
Property, plant and equipment, net	408		461
Other non-current assets	1		1
Non-current assets - discontinued operations	409		462
Accounts payable	19		28
Other current liabilities	5		6
Current liabilities - discontinued operations	24		34
Out-of-market contracts, net	50		66
Other non-current liabilities	11		10
Non-current liabilities - discontinued operations	$	61	$	76

Summarized results of discontinued operations were as follows:



	Year Ended December 31,
(In millions)	2018			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)/gain from operations of discontinued components, before tax	—			(154		)	92
Income tax expense	—			9			11
(Loss)/gain from discontinued operations	—			(163		)	81
Interest income - affiliate	3			8			11
Income/(loss) from discontinued operations, net of tax	3			(155		)	92
Pre-tax loss on deconsolidation	—			(208		)	—
Settlement consideration, insurance and services credit	63			(289		)	—
Pension and post-retirement liability assumption	21			(131		)	—
Other	(53		)	(6		)	—
Income/(loss) on disposal of discontinued operations, net of tax	31			(634		)	—
Income/(loss) from discontinued operations, net of tax	$	34		$	(789	)	$	92

Summarized results of South Central discontinued operations were as follows:



	Year Ended December 31,
(In millions)	2018			2017			2016
Operating revenues	$	410		$	422		$	467
Operating costs and expenses	(346		)	(335		)	(395		)
Other income	2			—			—
Gain from discontinued operations, net of tax	$	66		$	87		$	72

Summarized results of NRG Yield, Inc. and Renewables Platform and Carlsbad discontinued operations were as follows:



	Year Ended December 31,
(In millions)	2018			2017			2016
Operating revenues	$	909		$	1,164		$	1,165
Operating costs and expenses	(661		)	(1,114		)	(1,023		)
Other expenses	(174		)	(288		)	(261		)
Gain/(loss) from operations of discontinued components, before tax	74			(238		)	(119		)
Income tax expense/(benefit)	4			52			(20		)
Gain/(loss) from discontinued operations, net of tax	70			(290		)	(99		)
Loss on deconsolidation, net of tax	(134		)	—			—
California property tax indemnification	(153		)	—			—
Other Commitments, Indemnification and Fees	(75		)	—			—
Loss on disposal of discontinued operations, net of tax	(362		)	—			—
Loss from discontinued operations, net of tax	$	(292	)	$	(290	)	$	(99	)

The following table summarizes the major classes of assets and liabilities classified as discontinued operations as follows:



(In millions)	December 31, 2018 ^(a)		December 31, 2017 ^(b)
Cash and cash equivalents	$	—	$	224
Restricted Cash	4		229
Accounts receivable, net	10		119
Other current assets	5		81
Current assets - discontinued operations	19		653
Property, plant and equipment, net	590		7,473
Equity investments in affiliates	—		856
Intangible assets, net	9		1,240
Other non-current assets	4		475
Non-current assets - discontinued operations	603		10,044
Current portion of long term debt and capital leases	20		484
Accounts payable	27		169
Other current liabilities	1		159
Current liabilities - discontinued operations	48		812
Long-term debt and capital leases	572		6,536
Other non-current liabilities	2		186
Non-current liabilities - discontinued operations	$	574	$	6,722

- 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

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+ Details

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018				2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets
Notes receivable	$	17	$	14	$	2	$	2
Liabilities
Long-term debt, including current portion ^(a)	$	6,591	$	6,697	$	9,482	$	9,739

(a) 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, 2018				As of December 31, 2017
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	6,528	$	169	$	7,432	$	2,307

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



	As of December 31, 2018
	Fair Value
	Total		Level 1		Level 2		Level 3
	(In millions)
Investments in securities (classified within other current and non-current assets)	$	39	$	2	$	18	$	19
Nuclear trust fund investments:
Cash and cash equivalents	19		19		—		—
U.S. government and federal agency obligations	46		46		—		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	22		—		22		—
Corporate debt securities	96		—		96		—
Equity securities	312		312		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,042		137		796		109
Interest rate contracts	39		—		39		—
Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	64		—		—		—
Equity securities	8		—		—		—
Total assets	$	1,792	$	517	$	1,075	$	128
Derivative liabilities:
Commodity contracts	$	977	$	224	$	664	$	89
Total liabilities	$	977	$	224	$	664	$	89



	As of December 31, 2017
	Fair Value
	Total		Level 1		Level 2		Level 3

Investments in securities (classified within other current or non-current assets)	$	39	$	3	$	17	$	19
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	744		191		509		44
Interest rate contracts	39		—		39		—
Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	68		—		—		—
Equity securities	8		—		—		—
Total assets	$	1,523	$	616	$	768	$	63
Derivative liabilities:
Commodity contracts	$	674	$	257	$	358	$	59
Interest rate contracts	6		—		6		—
Total liabilities	$	680	$	257	$	364	$	59

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



	For the Year Ended December 31, 2018
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Debt Securities		Derivatives^(a)			Total
	(In millions)
Beginning balance as of January 1, 2018	$	19	$	(15	)	$	4
Contracts acquired in XOOM acquisition	—		12			12
Total losses realized/unrealized included in earnings	—		(21		)	(21		)
Purchases	—		41			41
Transfers into Level 3 ^(b)	—		5			5
Transfers out of Level 3 ^(b)	—		(2		)	(2		)
Ending balance as of December 31, 2018	$	19	$	20		$	39
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, 2018	$	—	$	(17	)	$	(17	)


(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, 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	$	(64	)	$	(47	)
Total gains realized/unrealized included in earnings	2		37			39
Purchases	—		(4		)	(4		)
Contracts reclassified to held-for-sale			4			4
Transfers into Level 3 ^(b)	—		(1		)	(1		)
Transfer out of Level 3 ^(b)	—		13			13
Ending balance as of December 31, 2017	$	19	$	(15	)	$	4
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	$	—	$	1		$	1


(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

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, 2018 and 2017:



	Significant Unobservable Inputs
	December 31, 2018
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	89	$	75	Discounted Cash Flow	Forward Market Price (per MWh)	$	1		$	214	$	31
FTRs	20		14		Discounted Cash Flow	Auction Prices (per MWh)	(90		)	34		—
	$	109	$	89



	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	$	33	$	47	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	142	$	24
FTRs	11		12		Discounted Cash Flow	Auction Prices (per MWh)	(28		)	46		—
	$	44	$	59

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, 2018 and 2017:



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)
Utilities, energy merchants, marketers and other	89	%
Financial institutions	11
Total	100	%



Category	Net Exposure^{(a) (b)} (% of Total)
Non-Investment grade/Non-Rated	51	%
Investment grade	49
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, 2018

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, 2018			December 31, 2017
		(In millions)
Emissions	Short Ton	(2		)	1
Renewables Energy Certificates	Certificates	1			—
Coal	Short Ton	13			21
Natural Gas	MMBtu	(330		)	(20		)
Oil	Barrels	1			—
Power	MWh	1			23
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	1,000		$	1,060
Equity	Shares	—			1

Fair Value Within the Derivative Instrument Valuation On the Balance Sheet

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, 2018		December 31, 2017		December 31, 2018		December 31, 2017
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	17	$	8	$	—	$	1
Interest rate contracts long-term	22		31		—		5
Commodity contracts current	747		616		673		536
Commodity contracts long-term	295		128		304		138
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	1,081	$	783	$	977	$	680

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, 2018	(In millions)
Commodity contracts:
Derivative assets	$	1,042		$	(778	)	$	(31	)	$	233
Derivative liabilities	(977		)	778			114			(85		)
Total commodity contracts	65			—			83			148
Interest rate contracts:
Derivative assets	39			—			—			39
Total interest rate contracts	39			—			—			39
Total derivative instruments	$	104		$	—		$	83		$	187



	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	$	744		$	(578	)	$	(11	)	$	155
Derivative liabilities	(674		)	578			72			(24		)
Total commodity contracts	70			—			61			131
Interest rate contracts:
Derivative assets	39			—			—			39
Derivative liabilities	(6		)	—			—			(6		)
Total interest rate contracts	33			—			—			33
Total derivative instruments	$	103		$	—		$	61		$	164

Effects on the Company's Accumulated OCI Balance Attributable to Cash Flow Hedge Derivatives, Net of Tax

The following table summarizes the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:



	Interest Rate Contracts
	2018			2017			2016
	(In millions)
Accumulated OCI beginning balance	$	(54	)	$	(66	)	$	(101	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	8			12			21
Mark-to-market of cash flow hedge accounting contracts	21			—			14
Sale of NRG Yield and Renewables	$	25		$	—		$	—
Accumulated OCI ending balance, net of $0, $8 and $16 tax	$	—		$	(54	)	$	(66	)

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,
	2018			2017			2016
	(In millions)
Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(73	)	$	47		$	(128	)
Reversal of acquired gain positions related to economic hedges	(10		)	—			(12		)
Net unrealized gains on open positions related to economic hedges	97			159			12
Total unrealized mark-to-market gains/(losses) for economic hedging activities	14			206			(128		)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(12		)	(25		)	10
Net unrealized gains on open positions related to trading activity	29			14			18
Total unrealized mark-to-market gains/(losses) for trading activity	17			(11		)	28
Total unrealized gains/(losses)	$	31		$	195		$	(100	)



	Year Ended December 31,
	2018			2017			2016
	(In millions)
Unrealized (losses)/gains included in operating revenues	$	(113	)	$	241		$	(608	)
Unrealized gains/(losses) included in cost of operations	144			(46		)	508
Total impact to statement of operations — energy commodities	$	31		$	195		$	(100	)
Total impact to statement of operations — interest rate contracts	$	—		$	4		$	(8	)

Nuclear Decommissioning Trust Fund (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018							As of December 31, 2017
(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	$	19	$	—	$	—	—	$	47	$	—	$	—	—
U.S. government and federal agency obligations	46		1		—		12	43		1		—		11
Federal agency mortgage-backed securities	100		1		2		23	82		1		1		23
Commercial mortgage-backed securities	22		—		1		22	14		—		—		20
Corporate debt securities	96		1		2		11	99		2		1		11
Equity securities	376		231		1		—	402		272		—		—
Foreign government fixed income securities	4		—		—		9	5		—		—		9
Total	$	663	$	234	$	6		$	692	$	276	$	2

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



	Year Ended December 31,
	2018			2017			2016
	(In millions)
Realized gains	$	17		$	22		$	26
Realized (losses)	(13		)	(8		)	(11		)
Proceeds from sale of securities	513			501			510

Inventory (Tables)

12 Months Ended

Dec. 31, 2018

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of:



	As of December 31,
	2018		2017
	(In millions)
Fuel oil	$	74	$	86
Coal	97		110
Natural gas	28		24
Spare parts	213		233
Total Inventory	$	412	$	453

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

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
	2018			2017			Lives
	(In millions)
Facilities and equipment	$	3,763		$	6,904		1-40 Years
Land and improvements	347			468
Nuclear fuel	212			235			5 Years
Office furnishings and equipment	431			421			2-10 Years
Construction in progress	106			201
Total property, plant, and equipment	4,859			8,229
Accumulated depreciation	(1,811		)	(2,255		)
Net property, plant, and equipment	$	3,048		$	5,974

Goodwill and Other Intangibles (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018	Emission Allowances			Fuel			Customer Contracts			Customer Relationships			Marketing Partnerships			Trade Names			Other			Total

January 1, 2018	$	755		$	49		$	1		$	768		$	88		$	342		$	77		$	2,080
Purchases	33			—			—			—			—			—			28			61
Acquisition of businesses^(a)	—			—			—			122			43			13			—			178
Usage	(1		)	—			—			—			—			—			(26		)	(27		)
Write-off of fully amortized balances	(107		)	—			—			(411		)	—			(10		)	—			(528		)
Impairment	(5		)	—			—			(1		)	—			—			—			(6		)
Other	(16		)	—			—			—			—			—			—			(16		)
December 31, 2018	659			49			1			478			131			345			79			1,742
Less accumulated amortization	(515		)	(45		)	(1		)	(314		)	(61		)	(195		)	(20		)	(1,151		)
Net carrying amount	$	144		$	4		$	—		$	164		$	70		$	150		$	59		$	591

(a) T

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	2018		2017		2016
	(In millions)
Emission allowances	$	39	$	71	$	62
Energy supply contracts	—		1		6
Fuel contracts	—		1		1
Customer relationships	32		34		48
Marketing partnerships	9		5		8
Trade names	23		23		23
Other	4		3		9
Total amortization	$	107	$	138	$	157

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:



Year Ended December 31,	Emission Allowances		Fuel Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other		Total
	(In millions)
2019	$	48	$	—	$	38	$	11	$	24	$	3	$	124
2020	37		1		39		11		25		3		116
2021	43		—		33		10		24		3		113
2022	50		—		23		10		24		3		110
2023	49		1		26		10		24		3		113

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,	Leases

2019	$	8
2020	8
2021	8
2022	8
2023	8

Debt and Capital Leases (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018			December 31, 2017			December 31, 2018 interest rate %^(a)

Recourse debt:
Senior Notes, due 2022	$	—		$	992		6.250
Senior Notes, due 2024	733			733			6.250
Senior Notes, due 2026	1,000			1,000			7.250
Senior Notes, due 2027	1,230			1,250			6.625
Senior Notes, due 2028	821			870			5.750
Convertible Senior Notes, due 2048	575			—			2.750
Term loan facility, due 2023	1,698			1,872			L+1.75
Tax-exempt bonds	466			465			4.125 - 6.00
Subtotal recourse debt	6,523			7,182
Non-recourse debt:
Ivanpah, due 2033 and 2038^(b)	—			1,073			2.285 - 4.256
Agua Caliente, due 2037^(c)	—			818			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	86			89			5.430
Midwest Generation, due 2019	48			152			4.390
Other ^(d)	34			180			various
Subtotal all non-recourse debt	168			2,312
Subtotal long-term debt (including current maturities)	6,691			9,494
Capital leases	1			5			various
Subtotal long-term debt and capital leases (including current maturities)	6,692			9,499
Less current maturities	(72		)	(204		)
Less debt issuance costs	(70		)	(103		)
Discounts	(101		)	(12		)
Total long-term debt and capital leases	$	6,449		$	9,180

(a) As of December 31, 2018, L+ equals 1-month LIBOR plus 1.75%

(b) The Company deconsolidated Ivanpah during the second quarter of 2018

(d) Guam was reclassified to held for sale during the fourth quarter of 2018

Debt includes the following discounts:



	As of December 31,
	2018			2017
	(In millions)
Term loan facility, due 2023	$	(4	)	$	(7	)
Midwest Generation, due 2019	(1		)	(5		)
Convertible Senior Notes, due 2048	(96		)	—
Total discounts	$	(101	)	$	(12	)

Annual Payments Based On the Maturities of NRG's Debt

As of December 31, 2018, annual payments based on the maturities of NRG's debt and capital leases are expected to be as follows:



	(In millions)
2019	$	74
2020	26
2021	27
2022	25
2023	1,635
Thereafter	4,905
Total	$	6,692

Debt Instrument Redemption



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	%

n 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
In millions, except percentages
5.750% senior notes due 2028	$	29	$	30	99.24	%
6.250% senior notes due 2022	14		15		103.25	%
Total at June 30, 2018	$	43	$	45
6.250% senior notes due 2022	493		512		103.13	%
5.750% senior notes due 2028	20		20		99.13	%
6.625% senior notes due 2027	20		21		103.06	%
Total at September 30, 2018	$	576	$	598
6.250% senior notes due 2022	485		508		103.13	%
Total at December 31, 2018	$	1,061	$	1,106



	Principal Repurchased		Cash Paid^(a)		Average Early Redemption Percentage
Amount in millions, except percentages
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 accrued interest of $29 million

n 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	%

n 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	%

Schedule of Tax Exempt Bonds

Tax Exempt Bonds



	As of December 31,
	2018		2017		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	33		32		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	$	466	$	465

- 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://fasb.org/us-gaap/role/ref/legacyRef
-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://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28541-108399

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21506-112644

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-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

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
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Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

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



	(In millions)
Balance as of December 31, 2017	$	679
Revisions in estimates for current obligations	(27		)
Additions	9
Spending for current obligations	(27		)
Accretion — Expense	30
Accretion — Nuclear decommissioning	15
Balance as of December 31, 2018	$	679

Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Schedule of Net Benefit Cost (Credit) Related to Pension and Other Postretirement Benefit Plans Components

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
	2018			2017			2016
	(In millions)
Service cost benefits earned	$	23		$	26		$	30
Interest cost on benefit obligation	44			43			43
Expected return on plan assets	(62		)	(58		)	(60		)
Amortization of unrecognized net loss	—			4			2
Settlement/curtailment expense	7			—			—
Net periodic benefit cost	$	12		$	15		$	15



	Year Ended December 31,
	Other Postretirement Benefits
	2018			2017			2016
	(In millions)
Service cost benefits earned	$	1		$	1		$	2
Interest cost on benefit obligation	4			4			6
Amortization of unrecognized prior service credit	(10		)	(9		)	(5		)
Amortization of unrecognized net (gain)/loss	—			(1		)	—
Curtailment gain	(10		)	—			—
Net periodic benefit (credit)/cost	$	(15	)	$	(5	)	$	3

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
	2018			2017			2018			2017
	(In millions)
Benefit obligation at January 1	$	1,329		$	1,241		$	128		$	128
Service cost	23			26			1			1
Interest cost	44			43			4			4
Plan amendments	17			—			(28		)	(1		)
Actuarial (gain)/loss	(95		)	77			(6		)	6
Employee and retiree contributions	—			—			3			3
Curtailment gain	(20		)	—			(7		)	—
Benefit payments	(76		)	(58		)	(12		)	(13		)
Benefit obligation at December 31	1,222			1,329			83			128
Fair value of plan assets at January 1	1,104			953			—			—
Actual return on plan assets	(80		)	173			—			—
Employee and retiree contributions	—			—			3			3
Employer contributions	33			36			9			10
Benefit payments	(76		)	(58		)	(12		)	(13		)
Fair value of plan assets at December 31	981			1,104			—			—
Funded status at December 31 — excess of obligation over assets	$	(241	)	$	(225	)	$	(83	)	$	(128	)
Less: GenOn postretirement obligation^(a)	—			—			—			38
Add: Retained obligation in bankruptcy proceeding^(a)	—			—			—			(25		)
Net obligation for NRG	$	(241	)	$	(225	)	$	(83	)	$	(115	)

(a)

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
	2018		2017		2018		2017
	(In millions)
Current liabilities	$	—	$	—	$	7	$	7
Less: GenOn other postretirement benefits	—		—		—		(3		)
Total current liabilities	$	—	$	—	$	7	$	4

Non-current liabilities	$	241	$	225	$	76	$	121
Less: GenOn other postretirement benefits	—		—		—		(10		)
Total non-current liabilities	$	241	$	225	$	76	$	111

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
	2018		2017			2018			2017
	(In millions)
Net loss/(gain)	$	90	$	53		$	(9	)	$	(4	)
Prior service cost/(credit)	3		3			(53		)	(37		)
Total accumulated OCI	$	93	$	56		$	(62	)	$	(41	)
Less: GenOn (deconsolidated June 14, 2017)	—		(22		)	—			10
Net accumulated OCI	$	93	$	34		$	(62	)	$	(31	)

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
	2018			2017			2018			2017
	(In millions)
Net actuarial loss/(gain)	$	47		$	(37	)	$	(5	)	$	6
Amortization of net actuarial (gain)/loss	—			(4		)	—			1
Curtailment	(27		)	—			2			—
Prior service credit	17			—			(28		)	(1		)
Amortization of prior service cost	—			—			10			9
Total recognized in OCI	$	37		$	(41	)	$	(21	)	$	15
Less: GenOn (deconsolidated June 14, 2017)	—			15			$	—		$	2
Net recognized in OCI	$	37		$	(26	)	$	(21	)	$	17
Less: GenOn post deconsolidation net periodic benefit cost	—			—			—			1
Net periodic benefit cost/(credit)	12			15			(15		)	(5		)
Net recognized in net periodic pension cost/(credit) and OCI	$	49		$	(11	)	$	(36	)	$	13

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
	2018		2017
	(In millions)
Projected benefit obligation	$	1,222	$	1,329
Accumulated benefit obligation	1,188		1,255
Fair value of plan assets	981		1,104

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, 2018
	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	$	—	$	183	$	183
Common/collective trust investment — non-U.S. equity	—		53		53
Common/collective trust investment — non-core assets	—		117		117
Common/collective trust investment — fixed income	—		256		256
Short-term investment fund	12		—		12
Subtotal fair value	$	12	$	609	$	621
Measured at net asset value practical expedient
Common/collective trust investment — non-U.S. equity					70
Common/collective trust investment — fixed income					249
Common/collective trust investment — non-core assets					16
Partnerships/joint ventures					25
Total fair value					$	981



	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

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	2018		2017		2018		2017
Discount rate	4.38	%	3.71	%	4.37	%	3.71	%
Rate of compensation increase	3.00	%	3.00	%	—	%	—
Health care trend rate	—		—		7.8% grading to 4.5% in 2025		8.2% grading to 4.5% 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	2018		2017		2016		2018	2017		2016
Discount rate	3.71%/4.04%		4.26	%	4.52	%	3.71%/4.08%	4.29	%	4.55	%
Expected return on plan assets	6.17	%	6.85	%	6.65	%	—	—		—
Rate of compensation increase	3.00	%	3.00	%	3.00	%	—	—		—
Health care trend rate	—		—		—		8.2% grading to 4.5% in 2025	7.0% grading to 5.0% in 2025		7.25% grading to 5.0% in 2025

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, 2018:



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

Schedule of Performance Benchmarks

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)
2019	$	72	$	7	$	—
2020	76		7		—
2021	79		7		—
2022	82		6		—
2023	85		6		—
2024-2028	418		26		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 postretirement benefit obligation	5	(4	)

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
	2018			2017			2018			2017
	(In millions)
Funded status — STPNOC benefit plans	$	(78	)	$	(76	)	$	(19	)	$	(24	)
Net periodic benefit cost/(credit)	8			8			(7		)	(3		)
Other changes in plan assets and benefit obligations recognized in other comprehensive (loss)/income	(7		)	(6		)	2			5

Defined Contribution Plan Contributions

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



	Year Ended December 31,
	2018		2017		2016
	(In millions)
Company contributions to defined contribution plans	$	28	$	56	$	55

Capital Structure (Tables)

12 Months Ended

Dec. 31, 2018

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, 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
Shares issued under ESPP	—	175,862		175,862
Shares issued under LTIPs	1,965,752	—		1,965,752
Share repurchases	—	(35,234,664	)	(35,234,664	)
Balance as of December 31, 2018	420,288,886	(136,638,847	)	283,650,039

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	17,631,031

Summary of shares repurchased

The following table summarizes the shares repurchased under the 2018 program, including shares repurchased under two completed accelerated repurchase agreements:



	Total number of shares purchased	Average price paid per share		Amounts paid for shares purchased (in millions)
Open market repurchases	11,097,631			$	396
Shares repurchased under May 24, 2018 Accelerated Repurchase Agreement	10,829,903			354
Shares repurchased under September 5, 2018 Accelerated Repurchase Agreement	13,307,130			500
Total Share Repurchases as of December 31, 2018	35,234,664			1,250
Additional open market repurchases through February 28, 2019	6,153,415			250
Total Share Repurchases as of February 28, 2019	41,388,079	$	36.24	$	1,500

Changes in redeemable preferred stock

The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended December 31, 2018, 2017, and 2016:



	(In millions)
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	$	—
Balance as of December 31, 2018	$	—

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

12 Months Ended

Dec. 31, 2018

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, 2018:



Name	Economic Interest		Investment Balance
			(In millions)
Agua Caliente	35.0	%	200
Gladstone	37.5	%	140
Ivanpah Master Holdings, LLC	54.5	%	37
Watson Cogeneration Company	49.0	%	17
Midway-Sunset Cogeneration Company	50.0	%	12
Other^(a)	Various		6
Total equity investments in affiliates			$	412

(a) Refer to Note 9, Asset Impairments, for discussion of NRG's investment in Petra Nova Parish Holdings, LLC

Undistributed earnings by equity investment



	As of December 31,
	2018		2017
	(In millions)
Undistributed earnings from equity investments	$	34	$	38

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, 2018		December 31, 2017
Current assets	$	3	$	6
Net property, plant and equipment	76		80
Other long-term assets	28		36
Total assets	107		122
Current liabilities	2		3
Long-term debt	29		30
Other long-term liabilities	7		7
Total liabilities	38		40
Redeemable noncontrolling interests	19		19
Net assets less noncontrolling interests	$	50	$	63

Earnings /Loss Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Reconciliation of NRG's basic and diluted earnings per share

The reconciliation of NRG's basic income/(loss) per share to diluted income/(loss) per share is shown in the following table:



	Year Ended December 31,
	2018		2017			2016
	(In millions, except per share amounts)
Basic income/(loss) per share attributable to NRG common stockholders
Net income/(loss) attributable to NRG Energy, Inc.	$	268	$	(2,153	)	$	(774	)
Dividends for preferred shares	—		—			5
Gain on redemption of 2.822% redeemable perpetual preferred shares	—		—			(78		)
Income/(Loss) Available to Common Stockholders	$	268	$	(2,153	)	$	(701	)
Weighted average number of common shares outstanding-basic	304		317			316
Income/(Loss) per weighted average common share — basic	$	0.88	$	(6.79	)	$	(2.22	)
Diluted income/(loss) per share attributable to NRG common stockholders
Weighted average number of common shares outstanding-basic	304		317			316
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	4		—			—
Total dilutive shares	308		317			316
Income/(Loss) per weighted average common share — diluted	$	0.87	$	(6.79	)	$	(2.22	)

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 income/(loss) per share:



	Year Ended December 31,
	2018	2017	2016
	(In millions of shares)
Equity compensation plans	—	5	5
2048 Convertible Senior Notes	7	—	—
Total	7	5	5

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Segment Reporting Information



	For the Year Ended December 31, 2018
	Retail ^(a)			Generation^(a)			Corporate^(a)			Eliminations			Total
	(In millions)
Operating revenues^(a)	$	7,103		$	3,432		$	11		$	(1,068	)	$	9,478
Operating expenses	5,919			3,019			125			(1,066		)	7,997
Depreciation and amortization	116			272			33			—			421
Impairment losses	1			98			—			—			99
Development costs	1			9			2			(1		)	11
Total operating cost and expenses	6,037			3,398			160			(1,067		)	8,528
Gain on sale of assets	—			2			30			—			32
Operating income/(loss)	1,066			36			(119		)	(1		)	982
Equity in earnings of unconsolidated affiliates	—			10			4			(5		)	9
Impairment losses on investments	—			(15		)	—			—			(15		)
Other income/(expenses), net	—			20			(1		)	(1		)	18
Loss on debt extinguishment	—			—			(44		)	—			(44		)
Interest expense	(3		)	(58		)	(422		)	—			(483		)
Income/(loss) from continuing operations before income taxes	1,063			(7		)	(582		)	(7		)	467
Income tax expense	1			—			6			—			7
Net income/(loss) from continuing operations	1,062			(7		)	(588		)	(7		)	460
Loss from discontinued operations, net of income tax	—			—			(192		)	—			(192		)
Net Income/(loss)	1,062			(7		)	(780		)	(7		)	268
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests	1			9			(5		)	(5		)	—
Net income/(loss) attributable to NRG Energy, Inc.	$	1,061		$	(16	)	$	(775	)	$	(2	)	$	268

Balance sheet
Equity investments in affiliates	$	—		$	412		$	—		$	—		$	412
Capital expenditures	90			267			31			—			388
Goodwill	408			165			—			—			573
Total assets	$	3,291		$	5,735		$	7,003		$	(5,401	)	$	10,628



(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues	$	9	$	1,085	$	(26	)	$	—	$	1,068



	For the Year Ended December 31, 2017
	Retail ^(a)			Generation^(a)			Corporate^(a)			Eliminations			Total
	(In millions)
Operating revenues^(a)	$	6,369		$	3,615		$	13		$	(923	)	$	9,074
Operating expenses	5,377			3,071			243			(925		)	7,766
Depreciation and amortization	110			454			35			(3		)	596
Impairment losses	8			1,526			—			—			1,534
Development costs	3			13			6			—			22
Total operating cost and expenses	5,498			5,064			284			(928		)	9,918
Other income - affiliate	—			—			87			—			87
Gain on sale of assets	—			15			1			—			16
Operating income/(loss)	871			(1,434		)	(183		)	5			(741		)
Equity in (losses)/earnings of unconsolidated affiliates	—			(14		)	5			(5		)	(14		)
Impairment losses on investments	—			(75		)	(4		)	—			(79		)
Other income, net	—			23			28			—			51
Loss on debt extinguishment	—			—			(49		)	—			(49		)
Interest expense	(6		)	(100		)	(451		)	—			(557		)
Income/(loss) from continuing operations before income taxes	865			(1,600		)	(654		)	—			(1,389		)
Income tax (benefit)/expense	(8		)	2			(38		)	—			(44		)
Net income/(loss) from continuing operations	873			(1,602		)	(616		)	—			(1,345		)
Loss from discontinued operations, net of income tax	—			—			(992		)	—			(992		)
Net Income/(loss)	873			(1,602		)	(1,608		)	—			(2,337		)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests	1			4			(189		)	—			(184		)
Net income/(loss) attributable to NRG Energy, Inc.	$	872		$	(1,606	)	$	(1,419	)	$	—		$	(2,153	)

Balance sheet
Equity investments in affiliates	$	—		$	179		$	95		$	(92	)	$	182
Capital expenditures	82			148			20			—			250
Goodwill	374			165			—			—			539
Total assets	$	2,655		$	9,090		$	17,402		$	(5,792	)	$	23,355



(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues	$	4	$	877	$	42	$	—	$	923



	For the Year Ended December 31, 2016
	Retail			Generation^(a)			Corporate^(a)			Eliminations			Total
	(In millions)
Operating revenues^(a)	$	6,330		$	3,633		$	74		$	(1,122	)	$	8,915
Operating expenses	5,162			3,322			353			(1,129		)	7,708
Depreciation and amortization	114			593			52			(3		)	756
Impairment losses	1			452			30			—			483
Development costs	4			15			29			—			48
Total operating costs and expenses	5,281			4,382			464			(1,132		)	8,995
Other income - affiliate	—			—			193			—			193
Loss on sale of assets	(1		)	—			(79		)	—			(80		)
Operating income/(loss)	1,048			(749		)	(276		)	10			33
Equity in (losses)/earnings of unconsolidated affiliates	—			(63		)	45			—			(18		)
Impairment losses on investments	—			(248		)	(20		)	—			(268		)
Other (expense)/income, net	(6		)	22			33			(2		)	47
Loss on debt extinguishment	—			—			(142		)	—			(142		)
Interest expense	6			(96		)	(495		)	2			(583		)
Income/(loss) from continuing operations before income taxes	1,048			(1,134		)	(855		)	10			(931		)
Income tax expense/(benefit)	1			(1		)	25			—			25
Net income/(loss) from continuing operations	$	1,047		$	(1,133	)	(880		)	10			(956		)
Income from discontinued operations, net of income tax	—			—			65			—			65
Net Income/(loss)	1,047			(1,133		)	(815		)	10			(891		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			(1		)	(104		)	(12		)	(117		)
Net income/(loss) attributable to NRG Energy, Inc.	$	1,047		$	(1,132	)	$	(711	)	$	22		$	(774	)



(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues	$	16	$	999	$	107	$	—	$	1,122

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018			2017			2016
	(In millions, except percentages)
Current
State	$	6		$	19		$	6
Total — current	6			19			6
Deferred
U.S. Federal	(16		)	(60		)	23
State	16			(5		)	(6		)
Foreign	1			2			2
Total — deferred	1			(63		)	19
Total income tax expense/(benefit)	$	7		$	(44	)	$	25
Effective income tax rate	1.5		%	3.2		%	(2.7		)%

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

The following represents the domestic and foreign components of income/(loss) from continuing operations before income taxes:



	Year Ended December 31,
	2018			2017			2016
	(In millions)
U.S.	$	468		$	(1,406	)	$	(942	)
Foreign	(1		)	17			11
Total	$	467		$	(1,389	)	$	(931	)

Reconciliation of the U.S. federal statutory rate to NRG's effective rate

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



	Year Ended December 31,
	2018			2017			2016
	(In millions, except percentages)
Income/(loss) from continuing operations before income taxes	$	467		$	(1,389	)	$	(931	)
Tax at federal statutory tax rate	98			(486		)	(326		)
State taxes	18			19			—
Foreign operations	—			2			10
Permanent differences	7			—			—
Tax Act - corporate income tax rate change	—			665			—
Valuation allowance due to corporate income tax rate change	—			(660		)	—
Valuation allowance - current period activities	(106		)	455			382
Impact of non-taxable equity earnings	—			(5		)	22
Book goodwill impairment	—			30			—
Net interest accrued on uncertain tax positions	—			—			1
Production tax credits ("PTC")	(7		)	(8		)	(7		)
Recognition of uncertain tax benefits	1			(5		)	2
State rate change including true-up to current period activity	—			—			(59		)
Alternative minimum tax ("AMT") refundable credit	(4		)	(64		)	—
Other	—			13			—
Income tax expense/(benefit)	$	7		$	(44	)	$	25
Effective income tax rate	1.5		%	3.2		%	(2.7		)%

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,
	2018			2017
	(In millions)
Deferred tax liabilities:
Emissions allowances	$	15		$	15
Derivatives, net	37			17
Investment in projects	180			337
Discount/premium on notes	—			1
Deferred financing costs	21			2
Other	1			5
Discontinued operations	36			49
Total deferred tax liabilities	290			426
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	134			141
Difference between book and tax basis of property	554			611
Goodwill	11			38
Differences between book and tax basis of contracts	38			52
Pension and other postretirement benefits	87			74
Equity compensation	9			10
Bad debt reserve	14			14
U.S. capital loss carryforwards	—			1
U.S. Federal net operating loss carryforwards	2,241			596
Foreign net operating loss carryforwards	62			66
State net operating loss carryforwards	379			128
Foreign capital loss carryforwards	1			1
Federal and state tax credit carryforwards	381			368
Federal benefit on state uncertain tax positions	6			7
Intangibles amortization (excluding goodwill)	21			98
Interest disallowance carryforward per §163(j) of the Tax Act	102			—
Inventory obsolescence	7			12
Discontinued operations	17			185
Total deferred tax assets	4,064			2,402
Valuation allowance	(3,812		)	(1,855		)
Discontinued operations	19			(8		)
Total deferred tax assets, net of valuation allowance	271			539
Net deferred tax (liability)/asset	$	(19	)	$	113

Summary of NRG's net deferred tax position

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



	As of December 31,
	2018			2017
	(In millions)
Deferred tax asset — continuing operations	$	46		$	6
Deferred tax asset — discontinued operations	—			128
Deferred tax liability— continuing operations	(65		)	(21		)
Net deferred tax (liability)/asset	$	(19	)	$	113

Reconciliation of total amounts of uncertain tax benefits

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



	As of December 31,
	2018			2017
	(In millions)
Balance as of January 1	$	30		$	34
Increase due to current year positions	4			4
Decrease due to prior year positions	—			(8		)
Decrease due to settlements and payments	(8		)	—
Uncertain tax benefits as of December 31	$	26		$	30

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

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, 2017	1,285,858		$	25.49	3	$	6
Expired	(36,866	)	43.64
Exercised	(969,058	)	24.93
Outstanding at December 31, 2018	279,934		25.04		2	4
Exercisable at December 31, 2018	279,934		25.04		2	4

(a) As of December 31, 2018, 26,430 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,
	2018		2017		2016
	(In millions)
Total intrinsic value of options exercised	$	10	$	1	$	—
Cash received from options exercised	24		4		—

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, 2017	2,377,813		$	14.63
Granted	447,309		28.90
Forfeited	(315,569	)	18.93
Vested	(1,051,471	)	17.67
Non-vested at December 31, 2018	1,458,082		16.16

(a) As of December 31, 2018, 7,319 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, 2017	427,148		$	21.54
Granted	61,645		33.43
Converted to Common Stock	(156,878	)	23.59
Outstanding at December 31, 2018	331,915		22.94

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, 2017	1,858,821		$	18.27
Granted	372,147		35.36
Forfeited	(134,473	)	22.26
Vested	(385,861	)	30.31
Non-vested at December 31, 2018	1,710,634		19.12

(a) There were no PSUs granted to GenOn employees and outstanding as of December 31, 2018

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:



	2018		2017		2016
	RPSUs		RPSUs		MSUs
Expected volatility	47.52	%	43.96	%	34.33	%
Expected term (in years)	3		3		3
Risk free rate	2.01	%	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	2018			2017			2016			2018		2018
	(In millions, except weighted average data)
NQSOs^(a)	$	—		$	—		$	—		$	—	0.00
RSUs	12			15			12			9		0.89
DSUs	2			2			2			—		0.00
MSUs	4			5			2			—		0.03
RPSUs	7			3			—			10		1.32
PRSUs^(b)	16			13			4			14		1.17
Total^(c)	$	41		$	38		$	20		$	33
Tax detriment recognized	$	(4	)	$	(5	)	$	(4	)

(a) All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2018, 2017, and 2016

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2018

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

The following table summarizes NRG's material related party transactions with third party affiliates:



	Year Ended December 31,
	2018		2017		2016
	(In millions)
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	3	$	3	$	2
GenConn	4		5		5
Ivanpah	20		—		—
Midway-Sunset	5		—		—
Total	$	32	$	8	$	7

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Future minimum lease commitments under operating leases

Future minimum lease commitments under operating leases for the years ending after December 31, 2018 are as follows:



Period^(a)	(In millions)
2019	$	60
2020	55
2021	43
2022	40
2023	39
Thereafter	95
Total	$	332

(a) Amounts in the table exclude future sublease income of $29 million associated with long-term leases for office locations

Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31, 2018 are as follows:



Period	(In millions)
2019	$	1
2020	1
2021	3
2022	6
2023	6
Thereafter	222
Total	$	239

Commitments under coal, gas and transportation contractual agreements

As of December 31, 2018, the Company's commitments under such outstanding agreements are as follows:



Period	(In millions)
2019	$	227
2020	156
2021	122
2022	74
2023	55
Thereafter	209
Total	$	843

Minimum purchase commitment obligations under purchased power agreements

Minimum purchase commitment obligations are as follows as of December 31, 2018:



Period	(In millions)
2019	$	30
2020	13
2021	12
2022	11
2023	1
Thereafter	1
Total ^(a)	$	68


(a)	As of December 31, 2018, the maximum remaining term under any individual purchased power contract is ten years

Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018		2017		2016
	(In millions)
Interest paid, net of amount capitalized	$	436	$	543	$	606
Income taxes paid, net of refunds	9		9		14
Non-cash investing and financing activities:
Additions to fixed assets for accrued capital expenditures	20		19		9

Guarantees (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018
Guarantees	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2017 Total
	(In millions)
Letters of credit and surety bonds^(a)(b)	$	1,138	$	79	$	—	$	36	$	1,253	$	1,003
Asset sales guarantee obligations	—		4		257		532		793		312
Other guarantees	—		105		—		616		721		645
Total guarantees	$	1,138	$	188	$	257	$	1,184	$	2,767	$	1,960


(a)	As of December 31, 2017 excludes $92 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn


(b)	December 31, 2018 includes $32 million of letter of credit and surety bonds for the benefit of GenOn where NRG holds cash or letter of credit to back stop the liability

Jointly Owned Plants (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018	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	%	$	382	$	(185	)	$	5
Cedar Bayou Unit 4, Baytown, TX	50.00	%	215		(84		)	8

Unaudited Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Summary of Unaudited Quarterly Financial Data

Summarized unaudited quarterly financial data is as follows:



	Quarter Ended
	2018
	December 31			September 30			June 30		March 31
	(In millions, except per share data)
Operating revenues	$	1,992		$	2,960		$	2,461	$	2,065
Operating income	49			398			174		361
Net (loss)/income from continuing operations	(93		)	288			27		238
Income/(loss) from discontinued operations	80			(336		)	69		(5		)
Net (loss)/income	(13		)	(48		)	96		233
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	(2		)	24			24		(46		)
(Loss)/income available to Common Stockholders	$	(11	)	$	(72	)	$	72	$	279
Weighted average number of common shares outstanding — basic	289			299			310		318
Income/(loss) from discontinued operations per weighted average common share — basic	$	0.28		$	(1.12	)	$	0.22	$	(0.02	)
Net (loss)/income per weighted average common share — basic	$	(0.04	)	$	(0.24	)	$	0.23	$	0.88
Weighted average number of common shares outstanding — diluted	289			299			314		322
Income/(loss) from discontinued operations per weighted average common share — diluted	$	0.28		$	(1.12	)	$	0.22	$	(0.02	)
Net (loss)/income per weighted average common share — diluted	$	(0.04	)	$	(0.24	)	$	0.23	$	0.87



	Quarter Ended
	2017
	December 31			September 30			June 30			March 31
	(In millions, except per share data)
Operating revenues	$	2,154		$	2,618		$	2,281		$	2,021
Operating (loss)/income	(1,200		)	275			214			(30		)
Net (loss)/income from continuing operations	(1,390		)	163			60			(178		)
(Loss)/income from discontinued operations	(265		)	—			(702		)	(25		)
Net (loss)/income	(1,655		)	163			(642		)	(203		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(120		)	(8		)	(16		)	(40		)
(Loss)/income available to Common Stockholders	$	(1,535	)	$	171		$	(626	)	$	(163	)
Weighted average number of common shares outstanding — basic	317			317			316			316
(Loss)/income from discontinued operations per weighted average common share — basic	$	(0.84	)	$	—		$	(2.22	)	$	(0.08	)
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
(Loss)/income from discontinued operations per weighted average common share — diluted	$	(0.84	)	$	—		$	(2.22	)	$	(0.08	)
Net (loss)/income per weighted average common share — diluted	$	(4.84	)	$	0.53		$	(1.98	)	$	(0.52	)

Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2018

Condensed Financial Information 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, 2018:



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

Condensed Consolidating Statement of Operations

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2018



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	8,119		$	1,385		$	—		$	(26	)	$	9,478
Operating Costs and Expenses
Cost of operations	6,147			959			28			(26		)	7,108
Depreciation and amortization	238			150			33			—			421
Impairment losses	6			93			—			—			99
Selling, general and administrative	462			63			348			(74		)	799
Reorganization costs	4			—			86			—			90
Development costs	—			1			11			(1		)	11
Total operating costs and expenses	6,857			1,266			506			(101		)	8,528
Gain on sale of assets	4			28			—			—			32
Operating Income/(Loss)	1,266			147			(506		)	75			982
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	23			—			1,291			(1,314		)	—
Equity in earnings/(losses) of unconsolidated affiliates	—			10			(1		)	—			9
Impairment losses on investments	—			(15		)	—			—			(15		)
Other income/(expense), net	32			(13		)	(1		)	—			18
Loss on debt extinguishment, net	—			—			(44		)	—			(44		)
Interest expense	(14		)	(49		)	(420		)	—			(483		)
Total other income/(expense)	41			(67		)	825			(1,314		)	(515		)
Income from Continuing Operations Before Income Taxes	1,307			80			319			(1,239		)	467
Income tax expense/(benefit)	372			19			(384		)	—			7
Income from Continuing Operations	935			61			703			(1,239		)	460
Income/(Loss) from Discontinued Operations, net of income tax	62			75			(329		)	—			(192		)
Net Income	997			136			374			(1,239		)	268
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	—			(181		)	106			75			—
Net Income Attributable to NRG Energy, Inc.	$	997		$	317		$	268		$	(1,314	)	$	268


(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, 2017



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,818		$	1,304		$	—		$	(48	)	$	9,074
Operating Costs and Expenses
Cost of operations	5,998			862			72			(46		)	6,886
Depreciation and amortization	343			221			32			—			596
Impairment losses	1,346			188			—			—			1,534
Selling, general and administrative	410			64			364			(2		)	836
Reorganization costs	6			—			38			—			44
Development costs	—			4			18			—			22
Total operating costs and expenses	8,103			1,339			524			(48		)	9,918
Other income - affiliate	—			—			87			—			87
Gain on sale of assets	4			12			—			—			16
Operating Loss	(281		)	(23		)	(437		)	—			(741		)
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	18			—			28			(46		)	—
Equity in losses of unconsolidated affiliates	—			(10		)	(4		)	—			(14		)
Impairment losses on investments	—			(75		)	(4		)	—			(79		)
Other income, net	9			14			28			—			51
Loss on debt extinguishment, net	—			—			(49		)	—			(49		)
Interest expense	(14		)	(91		)	(452		)	—			(557		)
Total other income/(expense)	13			(162		)	(453		)	(46		)	(648		)
Loss from Continuing Operations Before Income Taxes	(268		)	(185		)	(890		)	(46		)	(1,389		)
Income tax (benefit)/expense	(598		)	(62		)	616			—			(44		)
Income/(Loss) from Continuing Operations	330			(123		)	(1,506		)	(46		)	(1,345		)
Income/(Loss) from Discontinued Operations, net of income tax	91			(420		)	(663		)	—			(992		)
Net Income/(Loss)	421			(543		)	(2,169		)	(46		)	(2,337		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			(168		)	(16		)	—			(184		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	421		$	(375	)	$	(2,153	)	$	(46	)	$	(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.			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	7,539		$	1,450		$	—		$	(74	)	$	8,915
Operating Costs and Expenses
Cost of operations	5,581			1,116			59			(80		)	6,676
Depreciation and amortization	500			230			26			—			756
Impairment losses	370			113			—			—			483
Selling, general and administrative	430			144			458			—			1,032
Development costs	—			18			30			—			48
Total operating costs and expenses	6,881			1,621			573			(80		)	8,995
Other income - affiliate	—			—			193			—			193
Loss on sale of assets	(1		)	—			(79		)	—			(80		)
Operating Income/(Loss)	657			(171		)	(459		)	6			33
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries	(50		)	—			374			(324		)	—
Equity in earnings/(losses) of unconsolidated affiliates	5			(9		)	(4		)	(10		)	(18		)
Impairment losses on investments	—			(252		)	(16		)	—			(268		)
Other income, net	5			15			27			—			47
Net loss on debt extinguishment	—			(4		)	(138		)	—			(142		)
Interest expense	(15		)	(85		)	(483		)	—			(583		)
Total other expense	(55		)	(335		)	(240		)	(334		)	(964		)
Income/(Loss) from Continuing Operations Before Income Taxes	602			(506		)	(699		)	(328		)	(931		)
Income tax (benefit)/expense	(1		)	28			(2		)	—			25
Income/(Loss) from Continuing Operations	603			(534		)	(697		)	(328		)	(956		)
Income/(Loss) from Discontinued Operations, net of income tax	86			—			(21		)	—			65
Net Income/(Loss)	689			(534		)	(718		)	(328		)	(891		)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	—			(169		)	56			(4		)	(117		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	689		$	(365	)	$	(774	)	$	(324	)	$	(774	)


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

Condensed Consolidating Statements of Comprehensive Income

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the Year Ended December 31, 2018



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income	$	997		$	136		$	374		$	(1,239	)	$	268
Other Comprehensive Income, net of tax
Unrealized gain on derivatives, net	—			29			9			(15		)	23
Foreign currency translation adjustments, net	(10		)	(10		)	(13		)	22			(11		)
Available-for-sale securities, net	—			—			1			—			1
Defined benefit plan, net	(9		)	—			(35		)	9			(35		)
Other comprehensive (loss)/income	(19		)	19			(38		)	16			(22		)
Comprehensive Income	978			155			336			(1,223		)	246
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	—			(166		)	104			76			14
Comprehensive Income Attributable to NRG Energy, Inc.	$	978		$	321		$	232		$	(1,299	)	$	232


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Year Ended December 31, 2017



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income/(Loss)	$	421		$	(543	)	$	(2,169	)	$	(46	)	$	(2,337	)
Other Comprehensive Income/(Loss), 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	(13		)	30			41			(12		)	46
Other comprehensive (loss)/income	(6		)	50			58			(39		)	63
Comprehensive Income/(Loss)	415			(493		)	(2,111		)	(85		)	(2,274		)
Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			(103		)	(16		)	(60		)	(179		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	415		$	(390	)	$	(2,095	)	$	(25	)	$	(2,095	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Year Ended December 31, 2016



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Net Income/(Loss)	$	689		$	(534	)	$	(718	)	$	(328	)	$	(891	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net	—			32			89			(86		)	35
Foreign currency translation adjustments, net	(1		)	(1		)	(1		)	2			(1		)
Available-for-sale securities, net	—			—			1			—			1
Defined benefit plan, net	44			(13		)	(51		)	23			3
Other comprehensive income	43			18			38			(61		)	38
Comprehensive Income/(Loss)	732			(516		)	(680		)	(389		)	(853		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest	—			(103		)	56			(70		)	(117		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	732			(413		)	(736		)	(319		)	(736		)
Dividends for preferred shares	—			—			5			—			5
Gain on redemption of preferred shares	—			—			(78		)	—			(78		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	732		$	(413	)	$	(663	)	$	(319	)	$	(663	)


(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, 2018



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc.			Eliminations^(a)			Consolidated Balance
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	55	$	28		$	480		$	—		$	563
Funds deposited by counterparties	33		—			—			—			33
Restricted cash	7		10			—			—			17
Accounts receivable - trade	894		82			43			—			1,019
Inventory	278		134			—			—			412
Derivative instruments	779		50			16			(81		)	764
Cash collateral posted in support of energy risk management activities	275		12			—			—			287
Accounts receivable - affiliate	460		33			266			(754		)	5
Prepayments and other current assets	180		32			90			—			302
Current assets - held-for-sale	—		1			—			—			1
Current assets - discontinued operations	177		20			—			—			197
Total current assets	3,138		402			895			(835		)	3,600
Property, plant and equipment, net	1,938		957			153			—			3,048
Other Assets
Investment in subsidiaries	446		—			4,707			(5,153		)	—
Equity investments in affiliates	—		412			—			—			412
Goodwill	359		214			—			—			573
Intangible assets, net	422		169			—			—			591
Nuclear decommissioning trust fund	663		—			—			—			663
Derivative instruments	296		4			22			(5		)	317
Deferred income taxes	6		(143		)	183			—			46
Other non-current assets	133		71			97			(12		)	289
Non-current assets - held-for-sale	—		77			—			—			77
Non-current assets - discontinued operations	405		607			—			—			1,012
Total other assets	2,730		1,411			5,009			(5,170		)	3,980
Total Assets	$	7,806	$	2,770		$	6,057		$	(6,005	)	$	10,628
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	55		$	17		$	—		$	72
Accounts payable	693		64			105			—			862
Accounts payable - affiliate	675		(249		)	329			(754		)	1
Derivative instruments	713		41			—			(81		)	673
Cash collateral received in support of energy risk management activities	33		—			—			—			33
Accrued expenses and other current liabilities	291		36			353			—			680
Current liabilities - held-for-sale	—		5			—			—			5
Current liabilities - discontinued operations	24		48			—			—			72
Total current liabilities	2,429		—			804			(835		)	2,398
Other Liabilities
Long-term debt and capital leases	244		192			6,025			(12		)	6,449
Nuclear decommissioning reserve	282		—			—			—			282
Nuclear decommissioning trust liability	371		—			—			—			371
Postretirement and other benefit obligations	114		1			320			—			435
Derivative instruments	306		3			—			(5		)	304
Deferred income taxes	112		61			(108		)	—			65
Out-of-market contracts, net	—		121			—			—			121
Other non-current liabilities	288		198			232			—			718
Non-current liabilities - held-for-sale	—		65			—			—			65
Non-current liabilities - discontinued operations	58		577			—			—			635
Total non-current liabilities	1,775		1,218			6,469			(17		)	9,445
Total Liabilities	4,204		1,218			7,273			(852		)	11,843
Redeemable noncontrolling interest in subsidiaries	—		19			—			—			19
Stockholders' Equity	3,602		1,533			(1,216		)	(5,153		)	(1,234		)
Total Liabilities and Stockholders' Equity	$	7,806	$	2,770		$	6,057		$	(6,005	)	$	10,628


(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	$	—	$	150		$	620		$	—		$	770
Funds deposited by counterparties	37		—			—			—			37
Restricted cash	4		275			—			—			279
Accounts receivable - trade	852		44			4			—			900
Inventory	307		146			—			—			453
Derivative instruments	647		24			10			(57		)	624
Cash collateral posted in support of energy risk management activities	170		1			—			—			171
Accounts receivable - affiliate	685		183			(154		)	(534		)	180
Prepayments and other current assets	106		30			27			—			163
Current assets - held-for-sale	8		108			—			—			116
Current assets - discontinued operations	89		655			—			—			744
Total current assets	2,905		1,616			507			(591		)	4,437
Property, plant and equipment, net	2,052		3,689			237			(4		)	5,974
Other Assets
Investment in subsidiaries	266		—			8,234			(8,500		)	—
Equity investments in affiliates	—		181			1			—			182
Goodwill	359		180			—			—			539
Intangible assets, net	455		55			—			(3		)	507
Nuclear decommissioning trust fund	692		—			—			—			692
Derivative instruments	126		2			31			—			159
Deferred income taxes	377		(135		)	(236		)	—			6
Other non-current assets	64		126			120			—			310
Non-current assets - held for sale	—		43			—			—			43
Non-current assets - discontinued operations	456		10,072			—			(22		)	10,506
Total other assets	2,795		10,524			8,150			(8,525		)	12,944
Total Assets	$	7,752	$	15,829		$	8,894		$	(9,120	)	$	23,355
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	183		$	21		$	—		$	204
Accounts payable	582		47			55			—			684
Accounts payable - affiliate	725		(310		)	176			(534		)	57
Derivative instruments	556		38			—			(57		)	537
Cash collateral received in support of energy risk management activities	37		—			—			—			37
Accrued expenses and other current liabilities	313		67			376			—			756
Accrued expenses and other current liabilities - affiliate	—		—			161			—			161
Current liabilities - held-for-sale	—		72			—			—			72
Current liabilities - discontinued operations	34		807			5			—			846
Total current liabilities	2,247		904			794			(591		)	3,354
Other Liabilities
Long-term debt and capital leases	244		2,197			6,739			—			9,180
Nuclear decommissioning reserve	269		—			—			—			269
Nuclear decommissioning trust liability	415		—			—			—			415
Postretirement and other benefit obligations	118		1			339			—			458
Derivative instruments	136		7			—			—			143
Deferred income taxes	112		64			(155		)	—			21
Out-of-market contracts, net	—		129			—			—			129
Other non-current liabilities	284		198			52			—			534
Non-current liabilities - held-for-sale	—		8			—			—			8
Non-current liabilities - discontinued operations	73		6,725			—			—			6,798
Total non-current liabilities	1,651		9,329			6,975			—			17,955
Total Liabilities	3,898		10,233			7,769			(591		)	21,309
Redeemable noncontrolling interest in subsidiaries	—		78			—			—			78
Stockholders' Equity	3,854		5,518			1,125			(8,529		)	1,968
Total Liabilities and Stockholders' Equity	$	7,752	$	15,829		$	8,894		$	(9,120	)	$	23,355


(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, 2018



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net income	$	997		$	136		$	374		$	(1,239	)	$	268
Income/(loss) from discontinued operations	62			75			(329		)	—			(192		)
Net income from continuing operations	935			61			703			(1,239		)	460
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			47			(1		)	—			46
Depreciation, amortization and accretion	266			160			33			—			459
Provision for bad debts	79			6			—			—			85
Amortization of nuclear fuel	48			—			—			—			48
Amortization of financing costs and debt discount/premiums	—			6			23			—			29
Adjustment for debt extinguishment	—			—			44			—			44
Amortization of intangibles and out-of-market contracts	36			9			—			—			45
Amortization of unearned equity compensation	—			—			25			—			25
Net (gain)/loss on sale of assets and equity/cost method investments	(30		)	(20		)	1			—			(49		)
Impairment losses	5			109			—			—			114
Changes in derivative instruments	25			15			11			(14		)	37
Changes in deferred income taxes and liability for uncertain tax benefits	372			5			(372		)	—			5
Changes in collateral deposits in support of energy risk management activities	(94		)	(11		)	—			—			(105		)
Changes in nuclear decommissioning trust liability	60			—			—			—			60
GenOn settlement, net of insurance proceeds	—			—			(63		)	—			(63		)
Net loss on deconsolidation of Agua Caliente and Ivanpah projects	—			13			—			—			13
Changes in other working capital	311			(193		)	(1,621		)	1,253			(250		)
Cash provided/(used) by continuing operations	2,013			207			(1,217		)	—			1,003
Cash provided by discontinued operations	89			285			—			—			374
Net Cash Provided/(Used) by Operating Activities	2,102			492			(1,217		)	—			1,377
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(40		)	(203		)	—			—			(243		)
Capital expenditures	(192		)	(151		)	(45		)	—			(388		)
Net proceeds from sale of emission allowances	19			—			—			—			19
Investments in nuclear decommissioning trust fund securities	(572		)	—			—			—			(572		)
Proceeds from sales of nuclear decommissioning trust fund securities	513			—			—			—			513
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	14			8			1,542			—			1,564
Deconsolidation of Agua Caliente and Ivanpah projects	—			(268		)	—			—			(268		)
Changes in investments in unconsolidated affiliates	—			(39		)	—			—			(39		)
Net (contributions to)/distributions from discontinued operations	—			(60		)	—			—			(60		)
Other	—			—			(6		)	—			(6		)
Cash (used)/provided by continuing operations	(258		)	(713		)	1,491			—			520
Cash used by discontinued operations	—			(725		)	—			—			(725		)
Net Cash (Used)/Provided by Investing Activities	(258		)	(1,438		)	1,491			—			(205		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(1,701		)	113			1,588			—			—
Payments of dividends to preferred and common stockholders	—			—			(37		)	—			(37		)
Payments for treasury stock	—			—			(1,250		)	—			(1,250		)
Payments for debt extinguishment costs	—			—			(32		)	—			(32		)
Net distributions to noncontrolling interests from subsidiaries	—			(16		)	—			—			(16		)
Proceeds from issuance of common stock	—			—			21			—			21
Proceeds from issuance of long-term debt	—			163			937			—			1,100
Payments of debt issuance costs	—			—			(19		)	—			(19		)
Payments for short and long-term debt	—			(138		)	(1,596		)	—			(1,734		)
Receivable from affiliate	—			—			(26		)	—			(26		)
Other	—			(4		)	—			—			(4		)
Cash (used)/provided by continuing operations	(1,701		)	118			(414		)	—			(1,997		)
Cash provided by discontinued operations	—			471			—			—			471
Net Cash (Used)/Provided by Financing Activities	(1,701		)	589			(414		)	—			(1,526		)
Effect of exchange rate changes on cash and cash equivalents	—			1			—			—			1
Change in cash from discontinued operations	89			31			—			—			120
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	54			(387		)	(140		)	—			(473		)
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	41			425			620			—			1,086
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	95		$	38		$	480		$	—		$	613


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

NERGY, 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
	(In millions)
Cash Flows from Operating Activities
Net income/(loss)	$	421		$	(543	)	$	(2,169	)	$	(46	)	$	(2,337	)
Income/(loss) from discontinued operations	91			(420		)	(663		)	—			(992		)
Net income/(loss) from continuing operations	330			(123		)	(1,506		)	(46		)	(1,345		)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			12			90			—			102
Depreciation, amortization and accretion	343			221			32			—			596
Provision for bad debts	56			—			12			—			68
Amortization of nuclear fuel	51			—			—			—			51
Amortization of financing costs and debt discount/premiums	—			13			16			—			29
Adjustment for debt extinguishment	—			—			49			—			49
Amortization of intangibles and out-of-market contracts	42			12			—			—			54
Amortization of unearned equity compensation	—			—			35			—			35
Net loss/(gain) on sale of assets and equity/cost method investments	2			(11		)	—			—			(9		)
Impairment losses	1,346			264			4			—			1,614
Changes in derivative instruments	(214		)	50			(4		)	(2		)	(170		)
Changes in deferred income taxes and liability for uncertain tax benefits	(300		)	(9		)	322			—			13
Changes in collateral deposits in support of energy risk management activities	(98		)	18			—			—			(80		)
Changes in nuclear decommissioning trust liability	11			—			—			—			11
Changes in other working capital	82			(354		)	62			48			(162		)
Cash provided/(used) by continuing operations	1,651			93			(888		)	—			856
Cash provided by discontinued operations	116			638			—			—			754
Net Cash Provided/(Used) by Operating Activities	1,767			731			(888		)	—			1,610
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(14		)	—			—			—			(14		)
Capital expenditures	(180		)	(43		)	(31		)	—			(254		)
Proceeds from renewable energy grants	—			8			—			—			8
Net 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 of cash disposed and sale of discontinued operations, net of fees	33			54			343			—			430
Changes in investments in unconsolidated affiliates	—			(57		)	—			—			(57		)
Net distributions from discontinued operations	—			—			150			—			150
Other	18			4			—			—			22
Cash (used)/provided by continuing operations	(88		)	(34		)	462			—			340
Cash used by discontinued operations	(13		)	(966		)	—			—			(979		)
Net Cash (Used)/Provided by Investing Activities	(101		)	(1,000		)	462			—			(639		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(1,525		)	(39		)	1,564			—			—
Payment of dividends to preferred and common stockholders	—			—			(38		)	—			(38		)
Payments for debt extinguishment costs	—			—			(42		)	—			(42		)
Net distributions to noncontrolling interests from subsidiaries	—			(30		)	—			—			(30		)
Payments for issuance of common stock	—			—			(2		)	—			(2		)
Proceeds from issuance of long-term debt	—			94			1,084			—			1,178
Payment of debt issuance costs	—			(2		)	(16		)	—			(18		)
Payments for short and long-term debt	—			(183		)	(1,701		)	—			(1,884		)
Receivable from affiliate	—			—			(125		)	—			(125		)
Other	—			(8		)	—			—			(8		)
Cash (used)/provided by continuing operations	(1,525		)	(168		)	724			—			(969		)
Cash used by discontinued operations	(109		)	(60		)	—			—			(169		)
Net Cash (Used)/Provided by Financing Activities	(1,634		)	(228		)	724			—			(1,138		)
Effect of exchange rate changes on cash and cash equivalents	—			(1		)	—			—			(1		)
Change in cash from discontinued operations	(6		)	(388		)	—			—			(394		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	38			(110		)	298			—			226
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	3			535			322			—			860
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	41		$	425		$	620		$	—		$	1,086

(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)	$	689		$	(534	)	$	(718	)	$	(328	)	$	(891	)
Income/(loss) from discontinued operations	86			—			(21		)	—			65
Net income/(loss) from continuing operations	603			(534		)	(697		)	(328		)	(956		)
Adjustments to reconcile net income/(loss) to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	(5		)	(14		)	86			—			67
Depreciation, amortization and accretion	508			238			26			—			772
Provision for bad debts	42			3			—			—			45
Amortization of nuclear fuel	49			—			—			—			49
Amortization of financing costs and debt discount/premiums	—			13			20			—			33
Adjustment for debt extinguishment	—			4			138			—			142
Amortization of intangibles and out-of-market contracts	56			12			—			—			68
Amortization of unearned equity compensation	—			—			10			—			10
Net loss on sale of assets and equity/cost method investments	70			—			69			—			139
Impairment losses	370			365			16			—			751
Changes in derivative instruments	28			21			(36		)	3			16
Changes in deferred income taxes and liability for uncertain tax benefits	(1		)	49			(60		)	—			(12		)
Changes in collateral deposits in support of energy risk management activities	384			12			—			—			396
Changes in nuclear decommissioning trust liability	41			—			—			—			41
Changes in other working capital	(139		)	(54		)	(256		)	325			(124		)
Cash provided/(used) by continuing operations	2,006			115			(684		)	—			1,437
Cash provided by discontinued operations	174			297			—			—			471
Net Cash Provided/(Used) by Operating Activities	2,180			412			(684		)	—			1,908
Cash Flows from Investing Activities
Acquisition of business, net of cash acquired	—			—			—			—			—
Capital expenditures	(172		)	(326		)	(46		)	—			(544		)
Proceeds from renewable energy grants	—			36			—			—			36
Net purchases of emission allowances	(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 of cash disposed and sale of discontinued operations, net of fees	—			56			185			—			241
Changes in investments in unconsolidated affiliates	—			(33		)	—			—			(33		)
Net distributions to discontinued operations	—			—			(58		)	—			(58		)
Other	27			4			—			—			31
Cash (used)/provided by continuing operations	(187		)	(263		)	81			—			(369		)
Cash used by discontinued operations	(9		)	(379		)	—			—			(388		)
Net Cash (Used)/Provided by Investing Activities	(196		)	(642		)	81			—			(757		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(1,856		)	375			1,481			—			—
Payment of dividends to preferred and common stockholders	—			—			(76		)	—			(76		)
Payment for preferred shares	—			—			(226		)	—			(226		)
Payments for debt extinguishment costs	—			—			(121		)	—			(121		)
Net distributions to noncontrolling interest from subsidiaries	—			(27		)	—			—			(27		)
Proceeds from issuance of common stock	—			—			1			—			1
Proceeds from issuance of long-term debt	—			271			4,141			—			4,412
Payments of debt issuance costs	—			—			(61		)	—			(61		)
Payments for short and long-term debt	(2		)	(221		)	(4,923		)	—			(5,146		)
Other	(3		)	(4		)	—			—			(7		)
Cash (used)/provided by continuing operations	(1,861		)	394			216			—			(1,251		)
Cash (used)/provided by discontinued operations	(163		)	646			—			—			483
Net Cash (Used)/Provided by Financing Activities	(2,024		)	1,040			216			—			(768		)
Effect of exchange rate changes on cash and cash equivalents	—			1			—			—			1
Change in cash from discontinued operations	2			564			—			—			566
Net (Decrease)/Increase in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	(42		)	247			(387		)	—			(182		)
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	45			288			709			—			1,042
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	3		$	535		$	322		$	—		$	860

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

Nature of Business (Details) MW in Thousands	Dec. 31, 2018 MW
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Generation capacity (in MW)	23

Summary of Significant Accounting Policies - Net Income/(Loss) Attributable to Continuing and Discontinued Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Income/(loss) from continuing operations, net of income tax	$ 465	$ (977)	$ (733)
Loss from discontinued operations, net of income tax	(197)	(1,176)	(41)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$ 268	$ (2,153)	$ (774)

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Summary of Significant Accounting Policies - Additional (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ 32	$ 28
Project Development Costs and Capitalized Interest
Amount of interest capitalized	7	20	29
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, accumulated amortization	$ 1,151	1,573
Income Taxes
Unrecognized tax benefits, more-likely-than-not threshold percentage	50.00%
Lease Revenue
Lease, term of contract	20 years
Lessor Accounting
Contingent rental income	$ 104	253	272
Gross Receipts and Sales Taxes
Gross Receipts Tax	99	92	101
Cost of Energy for Retail Operations
Transmission and distribution charges not yet billed	105	107	90
Foreign Currency Translation and Transaction Gains and Losses
Cumulative translation adjustment	(13)	(2)	(11)
Marketing and Advertising Expense
Advertising expense	73	66	$ 79
Reorganization Costs
Severance costs	$ 90	$ 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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Cash and cash equivalents	$ 563	$ 770	$ 591
Funds deposited by counterparties	33	37	2
Restricted cash	17	279	267
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$ 613	$ 1,086	$ 860	$ 1,042

Summary of Significant Accounting Policies - Revenue Recognition (Details) - USD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings (accumulated deficit)	$ (6,022)		$ (6,268)
ASU 2014-09 \| Difference between Revenue Guidance in Effect before and after Topic 606
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings (accumulated deficit)		$ 15

Summary of Significant Accounting Policies - Capacity Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue from External Customer [Line Items]
Revenue from contract with customer					$ 8,148
Capacity revenue
Revenue from External Customer [Line Items]
Revenue from contract with customer					$ 670
Capacity revenue \| Scenario, Forecast
Revenue from External Customer [Line Items]
Revenue from contract with customer	$ 244	$ 532	$ 481	$ 618

Summary of Significant Accounting Policies - Contract Balances (Details) $ in Millions	Dec. 31, 2018 USD ($)
Schedule Of Contract Assets And Liabilities [Line Items]
Deferred customer acquisition costs	$ 111
Accounts receivable, net	1,022
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	392
Deferred revenues	67
Accounts receivable, net - Contracts with customers
Schedule Of Contract Assets And Liabilities [Line Items]
Accounts receivable, net	1,002
Accounts receivable, net - Derivative instruments
Schedule Of Contract Assets And Liabilities [Line Items]
Accounts receivable, net	$ 20

Summary of Significant Accounting Policies - Redeemable Non Controlling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Noncontrolling Interest [Line Items]
Balance at beginning of period	$ 78	$ 46	$ 29
Distributions to redeemable noncontrolling interest	(43)	(65)	(158)
Contributions from redeemable noncontrolling interest	26	99	33
Comprehensive loss attributable to redeemable noncontrolling interest	1	(72)	(38)
Net loss attributable to redeemable noncontrolling interest - discontinued operations	(27)
Deconsolidation of NRG Yield and the Renewables Platform	(2,548)
Balance at end of period	19	78	46
Redeemable noncontrolling interest
Noncontrolling Interest [Line Items]
Distributions to redeemable noncontrolling interest	(3)	(2)	(1)
Non-cash adjustments to redeemable noncontrolling interest	(8)	$ 7	$ 23
NRG Yield Inc. And Zephyr Renewables
Noncontrolling Interest [Line Items]
Deconsolidation of NRG Yield and the Renewables Platform	$ (48)

Summary of Significant Accounting Policies - Recent Accounting Developments - Guidance Adopted in 2017 (Details) - Subsequent Event - ASU 2016-02	Jan. 01, 2019 USD ($)
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease liability	$ 380,000,000
Right-of-use assets	300,000,000
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease liability	420,000,000
Right-of-use assets	$ 340,000,000

Acquisitions, Discontinued Operations and Dispositions - Acquisitions (Details) customer in Thousands, $ in Millions		12 Months Ended
	Jun. 01, 2018 USD ($) state customer	Dec. 31, 2018 USD ($) customer	Dec. 31, 2017 USD ($)
Business Acquisition [Line Items]
Goodwill		$ 573	$ 539
XOOM Energy, LLC
Business Acquisition [Line Items]
Number of states in which the entity operates \| state	19
Consideration transferred	$ 213
Customers acquired \| customer	300
Net current and non-current working capital	$ 46
Other intangible assets	133
Goodwill	$ 34
Small Book Acquisitions
Business Acquisition [Line Items]
Consideration transferred		$ 44
Customers acquired \| customer		115

Acquisitions, Discontinued Operations and Dispositions - Discontinued Operations (Details) $ in Millions			3 Months Ended								12 Months Ended
	Aug. 31, 2018 USD ($)	Feb. 06, 2018 USD ($) extension	Dec. 31, 2018 USD ($) MW	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) \| MW			23,000								23,000
Other non-current liabilities			$ 718				$ 534				$ 718	$ 534
Loss from discontinued operations			$ (80)	$ 336	$ (69)	$ 5	$ 265	$ 0	$ 702	$ 25	$ 192	992	$ (65)
NRG Yield Inc. And Zephyr Renewables \| Agua Caliente Solar Project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest prior to disposal	5100.00%
Remaining ownership interest	3500.00%
Gain on sale of equity interest	$ 8
Discontinued Operations \| South Central Portfolio
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) \| MW			1,263								1,263
Loss from discontinued operations											$ (66)	(87)	(72)
Discontinued Operations \| NRG Yield Inc. And Zephyr Renewables
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration	1,348
Commitment and advisory fees	50
Discontinued Operations \| NRG Yield Inc. And Zephyr Renewables \| Scenario, Adjustment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other non-current liabilities	$ (153)
Loss from discontinued operations		$ 153
Discontinued Operations \| Carlsbad Energy Holdings LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration		387
Other commitment		$ 23
Loss from discontinued operations											$ 292	$ 290	$ 99
Membership percentage		100.00%
Lease and easement agreement, number of extensions \| extension		2
Renewal term		10 years

Acquisitions, Discontinued Operations and Dispositions - Summary of Results (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on deconsolidation, net of tax									$ (13)	$ 0	$ 0
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$ 80	$ (336)	$ 69	$ (5)	$ (265)	$ 0	$ (702)	$ (25)	(192)	(992)	65
Carlsbad Energy Holdings LLC \| Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues									909	1,164	1,165
Operating costs and expenses									(661)	(1,114)	(1,023)
Other expenses									(174)	(288)	(261)
(Loss)/gain from operations of discontinued components, before tax									74	(238)	(119)
Income tax expense									4	52	(20)
(Loss)/Income from operations of discontinued components, net of tax									70	(290)	(99)
Loss on deconsolidation, net of tax									(134)	0	0
California property tax indemnification									(153)	0	0
Other									(75)	0	0
Loss on disposal of discontinued components, net of tax									(362)	0	0
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent									(292)	(290)	(99)
South Central Portfolio \| Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues									410	422	467
Operating costs and expenses									(346)	(335)	(395)
Other income									2	0	0
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent									66	87	72
GenOn \| Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues									0	646	1,862
Operating costs and expenses									0	(702)	(1,896)
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0	0	294
Other expenses									0	(98)	(168)
(Loss)/gain from operations of discontinued components, before tax									0	(154)	92
Income tax expense									0	9	11
(Loss)/gain from discontinued operations									0	(163)	81
Interest income - affiliate									3	8	11
(Loss)/Income from operations of discontinued components, net of tax									3	(155)	92
Pre-tax loss on deconsolidation									0	(208)	0
Settlement consideration and services credit									63	(289)	0
Pension and post-retirement liability assumption									21	(131)	0
Other									(53)	(6)	0
Loss on disposal of discontinued components, net of tax									31	(634)	0
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent									$ 34	$ (789)	$ 92

Acquisitions, Discontinued Operations and Dispositions - Major Classes of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other current assets	$ 1	$ 116
Current assets - discontinued operations	197	744
Other non-current assets	77	43
Non-current assets - discontinued operations	1,012	10,506
Current liabilities - discontinued operations	72	846
Other non-current liabilities	65	8
Non-current liabilities - discontinued operations	635	6,798
Zephyr Renewables And Carlsbad Energy Holdings LLC [Member] \| Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and cash equivalents	0	224
Restricted Cash	4	229
Accounts receivable, net	10	119
Other current assets	5	81
Current assets - discontinued operations	19	653
Property, plant and equipment, net	590	7,473
Equity investments in affiliates	0	856
Intangible assets, net	9	1,240
Other non-current assets	4	475
Non-current assets - discontinued operations	603	10,044
Current portion of long term debt and capital leases	20	484
Accounts payable	27	169
Other current liabilities	1	159
Current liabilities - discontinued operations	48	812
Long-term debt and capital leases	572	6,536
Other non-current liabilities	2	186
Non-current liabilities - discontinued operations	574	6,722
South Central Portfolio \| Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and cash equivalents	89	(3)
Accounts receivable, net	49	61
Inventory	35	33
Other current assets	5	0
Current assets - discontinued operations	178	91
Property, plant and equipment, net	408	461
Other non-current assets	1	1
Non-current assets - discontinued operations	409	462
Accounts payable	19	28
Other current liabilities	5	6
Current liabilities - discontinued operations	24	34
Out-of-market contracts	50	66
Other non-current liabilities	11	10
Non-current liabilities - discontinued operations	$ 61	$ 76

Acquisitions, Discontinued Operations and Dispositions - Dispositions (Details) $ in Millions					12 Months Ended
	Nov. 01, 2018 USD ($) MW	Aug. 01, 2018 USD ($)	Jun. 29, 2018 USD ($)	Jun. 28, 2018 USD ($)	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) \| MW					23,000
Parent guarantee					$ 2,767	$ 1,960
Other guarantees
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Parent guarantee					721	$ 645
Agua Caliente Borrower 1, LLC \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of ownership interest	$ 120
Generation capacity (in MW) \| MW	290
BETM \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of ownership sold		100.00%
Proceeds from sale of businesses, net of working capital adjustments		$ 71
Gain on sale of business		15
Cash collateral		4
BETM \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations \| Letter of Credit
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Parent guarantee		119
BETM \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations \| Other guarantees
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Parent guarantee		$ 32
Canal Three \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of business			$ 17
Cash received			$ 16
Cash proceeds				$ 167
Proceeds distributed to Company				$ 151
Other \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash received					$ 28
Clearway Energy, Inc. \| Agua Caliente Borrower 1, LLC \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest	35.00%

Acquisitions, Discontinued Operations and Dispositions - Sale of Assets Prior to Discontinued (Details) $ in Millions	Jan. 11, 2019 USD ($)	Dec. 31, 2018 MW	Jun. 19, 2018 USD ($)	Mar. 30, 2018 USD ($) MW	Mar. 27, 2017 USD ($) MW	Sep. 01, 2016 USD ($)
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW		23,000
UPMC Thermal Project
Business Acquisition [Line Items]
Cash consideration			$ 84.0
Buckthorn Renewables, LLC
Business Acquisition [Line Items]
Cash consideration				$ 42.0
Percentage of ownership sold				100.00%
Generation capacity (in MW) \| MW				154
Debt assumed				$ 183.0
Agua Caliente Solar Project
Business Acquisition [Line Items]
Cash consideration					$ 130.0
Debt assumed					328.0
Working capital adjustments					$ 1.0
Agua Caliente Solar Project \| Agua Caliente
Business Acquisition [Line Items]
Percentage of ownership sold					16.00%
Generation capacity (in MW) \| MW					46
Agua Caliente Solar Project \| Utah Portfolio
Business Acquisition [Line Items]
Generation capacity (in MW) \| MW					265
Number Of utility scale solar projects \| MW					7
CVSR
Business Acquisition [Line Items]
Cash consideration						$ 78.5
Percentage of ownership sold						51.05%
Debt assumed						$ 496.0
Subsequent Event \| UPMC Thermal Project
Business Acquisition [Line Items]
Cash consideration	$ 3.0

Acquisitions, Discontinued Operations and Dispositions - GenOn Settlement and Plan Confirmation (Details) - USD ($) $ in Millions			1 Months Ended	12 Months Ended
	Jul. 16, 2018	Apr. 27, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Collateral posted				$ 26.0	$ 125.0	$ 0.0
GenOn Mid-Atlantic \| Restructuring Support Agreement \| Letter of Credit \| Intercompany Credit Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Letters of credit facility		$ 37.5
Services Agreement \| GenOn \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Collateral posted	$ 15.0
GenOn
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Settlement consideration	261.0
Deduction for GenOn tax losses				$ 9,500.0
Professional fees		$ 6.0
GenOn \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Settlement consideration	125.0
GenOn \| Services Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Credit applied			$ 28.0
GenOn \| Services Agreement \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Credit applied	28.0
Remaining payments and other balances due under settlement agreement	10.0
GenOn \| Revolving Credit Facility Borrowings \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Intercompany secured revolving credit facility and accrued interest and fees	151.0
GenOn \| Accrued Interest On Borrowings \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Intercompany secured revolving credit facility and accrued interest and fees	12.0
GenOn \| Other \| Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Remaining payments and other balances due under settlement agreement	2.0
GenOn \| Assignment Of Historical Claims Against REMA
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Remaining payments and other balances due under settlement agreement	8.0
GenOn \| Reduction Of Settlement Payment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Remaining payments and other balances due under settlement agreement	$ 4.0

Acquisitions, Discontinued Operations 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, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale			$ (49)	$ (9)	$ 139
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
Cash received	17
Working capital adjustments	3
Capital contributions	15
Future capital contributions	7
Future earnout potential	70
Financial obligations under agreement	$ 103
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
Loss on sale of equity interest		$ 27
Remaining obligation	$ 56		$ 6
Remaining ownership interest			23.70%

Acquisitions, Discontinued Operations 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 ($)	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) \| MW				23,000
Impairment losses				$ 99	$ 1,534	$ 483
Rockford
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
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
Adjustments for base residual auction results	$ 1

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, 2018	Dec. 31, 2017
Liabilities
Long-term debt, including current portion	$ 6,691	$ 9,494
Level 2
Debt, Long-term and Short-term, Combined Amount [Abstract]
Long-term debt, including current portion	6,528	7,432
Level 3
Debt, Long-term and Short-term, Combined Amount [Abstract]
Long-term debt, including current portion	169	2,307
Carrying Amount
Assets
Notes receivable	17	2
Liabilities
Long-term debt, including current portion	6,591	9,482
Fair Value Measurement
Assets
Notes receivable	14	2
Liabilities
Long-term debt, including current portion	$ 6,697	$ 9,739

Fair Value of Financial Instruments - Reconciliation of Level 3 Financial Instruments (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 4	$ (47)
Total losses realized/unrealized included in earnings
Contracts acquired in XOOM acquisition	12
Included in earnings	(21)	39
Purchases	41	(4)
Contracts reclassified to held-for-sale		4
Transfers into Level 3	5	(1)
Transfers out of Level 3	(2)	13
Ending balance	39	4
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	(17)	1
Debt Securities
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	19	17
Total losses realized/unrealized included in earnings
Included in earnings		2
Purchases	0	0
Contracts reclassified to held-for-sale
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Ending balance	19	19
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	0
Derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(15)	(64)
Total losses realized/unrealized included in earnings
Contracts acquired in XOOM acquisition	12
Included in earnings	(21)	37
Purchases	41	(4)
Contracts reclassified to held-for-sale		4
Transfers into Level 3	5	(1)
Transfers out of Level 3	(2)	13
Ending balance	20	(15)
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	$ (17)	$ 1

Fair Value of Financial Instruments - Derivative Fair Value Measurements Narrative (Details)	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Total derivative assets valued with prices provided by models and other valuation techniques percentage	10.00%
Total derivative liabilities valued with prices provided by models and other valuation techniques, percentage	9.00%

Fair Value of Financial Instruments - Derivative Fair Value Measurement (Details) $ in Millions	Dec. 31, 2018 USD ($) $ / MWh	Dec. 31, 2017 USD ($) $ / MWh
Fair Value Inputs [Abstract] (Deprecated 2018-01-31)
Cash collateral posted in support of energy risk management activities	$ 287	$ 171
Cash collateral received in support of energy risk management activities	33	37
Commodity contracts
Assets
Derivative assets	1,042	744
Liabilities
Derivative liabilities	977	674
Fair Value Inputs [Abstract] (Deprecated 2018-01-31)
Cash collateral posted in support of energy risk management activities	114	72
Cash collateral received in support of energy risk management activities	31	11
Commodity contracts \| Fair Value, Measurements, Recurring
Assets
Derivative assets	1,042	744
Liabilities
Derivative liabilities	977	674
Commodity contracts \| Fair Value, Measurements, Recurring \| Level 3
Assets
Derivative assets	109	44
Liabilities
Derivative liabilities	89	59
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3
Assets
Derivative assets	89	33
Liabilities
Derivative liabilities	$ 75	$ 47
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3 \| Low
Fair Value Inputs [Abstract] (Deprecated 2018-01-31)
Forward Market Price (USD per MWh) \| $ / MWh	1	10
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3 \| High
Fair Value Inputs [Abstract] (Deprecated 2018-01-31)
Forward Market Price (USD per MWh) \| $ / MWh	214	142
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3 \| Weighted Average
Fair Value Inputs [Abstract] (Deprecated 2018-01-31)
Forward Market Price (USD per MWh) \| $ / MWh	31	24
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3
Assets
Derivative assets	$ 20	$ 11
Liabilities
Derivative liabilities	$ 14	$ 12
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3 \| Low
Fair Value Inputs [Abstract] (Deprecated 2018-01-31)
Auction Prices (USD per MWh) \| $ / MWh	(90)	(28)
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3 \| High
Fair Value Inputs [Abstract] (Deprecated 2018-01-31)
Auction Prices (USD per MWh) \| $ / MWh	34	46
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3 \| Weighted Average
Fair Value Inputs [Abstract] (Deprecated 2018-01-31)
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, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Fair Value Meaurements and Concentration of Credit Risk
Counterparty credit exposure, excluding credit risk exposure under certain long term agreements	$ 301
Counterparty credit exposure, collateral held (cash and letters of credit) against positions	123
Counterparty credit exposure, net	$ 180
Company's exposure before collateral expected to roll off by the end of 2015 (as a percent)	66.00%
Net exposure (as a percent)	100.00%
Counterparty credit risk exposure to certain counterparties, threshold (as a percent)	10.00%
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	$ 434
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	$ 85	$ 68	$ 45
Non-Investment grade/Non-Rated
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	51.00%
Investment grade
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	49.00%
Financial Institutions
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	89.00%
Financial institutions
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	11.00%

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, 2018 USD ($) MWh MMBTU T shares bbl	Dec. 31, 2017 USD ($) MWh MMBTU T shares bbl
Long \| Emissions
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton)		1
Long \| Renewables Energy Certificates
Derivative [Line Items]
Derivative, non-monetary notional amount (in shares) \| shares	1	0
Long \| Coal
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton)	13	21
Long \| Oil
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels) \| bbl	1	0
Long \| Power
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) \| MWh	1	23
Long \| Interest
Derivative [Line Items]
Derivative, notional amount (in usd) \| $	$ 1,000	$ 1,060
Long \| Equity
Derivative [Line Items]
Derivative, non-monetary notional amount (in shares) \| shares	0	1
Short \| Emissions
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton)	2
Short \| Natural Gas
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) \| MMBTU	330	20
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) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative assets	$ 1,081	$ 783
Derivative liabilities	977	680
Interest rate contracts current
Derivative [Line Items]
Derivative assets	17	8
Derivative liabilities	0	1
Interest rate contracts long-term
Derivative [Line Items]
Derivative assets	22	31
Derivative liabilities	0	5
Commodity contracts current
Derivative [Line Items]
Derivative assets	747	616
Derivative liabilities	673	536
Commodity contracts long-term
Derivative [Line Items]
Derivative assets	295	128
Derivative liabilities	$ 304	$ 138

Accounting for Derivative Instruments and Hedging Activities - Offsetting of Derivatives by Counterparty Master Agreement level and Collateral Received (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Cash Collateral (Held)/Posted	$ (33)	$ (37)
Cash collateral posted in support of energy risk management activities	287	171
Gross Amounts of Recognized Assets / Liabilities	104	103
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	83	61
Net Amount	187	164
Commodity contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	1,042	744
Derivative Instruments	(778)	(578)
Cash Collateral (Held)/Posted	(31)	(11)
Net Amount	233	155
Derivative liabilities	(977)	(674)
Derivative Instruments	778	578
Cash collateral posted in support of energy risk management activities	114	72
Net Amount	(85)	(24)
Gross Amounts of Recognized Assets / Liabilities	65	70
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	83	61
Net Amount	148	131
Interest rate contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	39	39
Derivative Instruments	0	0
Cash Collateral (Held)/Posted	0	0
Net Amount	39	39
Derivative liabilities		(6)
Derivative Instruments		0
Cash collateral posted in support of energy risk management activities		0
Net Amount		(6)
Gross Amounts of Recognized Assets / Liabilities	39	33
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	0	0
Net Amount	$ 39	$ 33

Accounting for Derivative Instruments and Hedging Activities - Effect on the Company's of Accumulated OCI Balance Attributable to Cash Flow Hedge Derivatives, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Effect of ASC 815 on NRG's Accumulated OCI Balance Attributable to Cash Flow Hedge Derivatives
Accumulated OCI beginning balance	$ (101)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	21
Mark-to-market of cash flow hedge accounting contracts	14
Sale of NRG Yield and Renewables	25	$ 0	$ 0
Accumulated OCI ending balance, net of $0, $8 and $16 tax	(66)	(101)
Accumulated OCI income (loss), tax	0	(8)	(16)
2018
Effect of ASC 815 on NRG's Accumulated OCI Balance Attributable to Cash Flow Hedge Derivatives
Accumulated OCI beginning balance	(54)	(66)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	8	12
Mark-to-market of cash flow hedge accounting contracts	21	0
Accumulated OCI ending balance, net of $0, $8 and $16 tax	$ 0	$ (54)	$ (66)

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Unrealized Mark To Market Results [Abstract]
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$ (73)	$ 47	$ (128)
Reversal of acquired gain positions related to economic hedges	(10)	0	(12)
Net unrealized gains on open positions related to economic hedges	97	159	12
Total unrealized mark-to-market gains/(losses) for economic hedging activities	14	206	(128)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(12)	(25)	10
Net unrealized gains on open positions related to trading activity	29	14	18
Total unrealized mark-to-market gains/(losses) for trading activity	17	(11)	28
Total unrealized gains/(losses)	31	195	(100)
Credit Risk Related Contingent Features [Abstract]
Collateral required contracts with credit rating contingent features in a net liability position	11
Adequate Assurance Clauses
Credit Risk Related Contingent Features [Abstract]
Collateral required for contracts in net liability positions that have adequate assurance clauses	16
Credit Rating Contingent Features
Credit Risk Related Contingent Features [Abstract]
Collateral required for contracts in net liability positions that have adequate assurance clauses	14
Commodity contracts
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	31	195	(100)
Commodity contracts \| Operating revenue
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	(113)	241	(608)
Commodity contracts \| Cost of operations
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	144	(46)	508
Interest rate contracts
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	$ 0	$ 4	$ (8)

Nuclear Decommissioning Trust Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Nuclear decommissioning trust fund disclosure
Fair Value	$ 663	$ 692
Unrealized Gains	234	276
Unrealized Losses	6	2
Proceeds from sales of available-for-sale securities and the related realized gains and losses
Realized gains	17	22	$ 26
Realized (losses)	(13)	(8)	(11)
Proceeds from sale of securities	513	501	$ 510
Cash and cash equivalents
Nuclear decommissioning trust fund disclosure
Fair Value	19	47
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	$ 46	$ 43
Unrealized Gains	1	1
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	12 years	11 years
Federal agency mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 100	$ 82
Unrealized Gains	1	1
Unrealized Losses	$ 2	$ 1
Weighted- average maturities (in years)	23 years	23 years
Commercial mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 22	$ 14
Unrealized Gains	0	0
Unrealized Losses	$ 1	$ 0
Weighted- average maturities (in years)	22 years	20 years
Corporate debt securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 96	$ 99
Unrealized Gains	1	2
Unrealized Losses	$ 2	$ 1
Weighted- average maturities (in years)	11 years	11 years
Equity securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 376	$ 402
Unrealized Gains	231	272
Unrealized Losses	$ 1	$ 0
Weighted- average maturities (in years)	0 years	0 years
Foreign government fixed income securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 4	$ 5
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, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Fuel oil	$ 74	$ 86
Coal	97	110
Natural gas	28	24
Spare parts	213	233
Total Inventory	412	453
Inventory Write-down	$ 3	$ 33

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment
Total property, plant and equipment	$ 4,859	$ 8,229
Accumulated depreciation	(1,811)	(2,255)
Net property, plant, and equipment	3,048	5,974
Facilities and equipment
Property, Plant and Equipment
Total property, plant and equipment	$ 3,763	6,904
Facilities and equipment \| Minimum
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	$ 347	468
Nuclear fuel
Property, Plant and Equipment
Total property, plant and equipment	$ 212	235
Depreciable lives (in years)	5 years
Office furnishings and equipment
Property, Plant and Equipment
Total property, plant and equipment	$ 431	421
Office furnishings and equipment \| Minimum
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	$ 106	$ 201

Asset Impairments (Details) - USD ($)			3 Months Ended					12 Months Ended
Asset Impairments (Details) - USD ($)	Jun. 29, 2018	May 12, 2016	Dec. 31, 2018	Jun. 30, 2018	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 20, 2019	Mar. 31, 2016
Asset Impairments
Impairment losses								$ 99,000,000	$ 1,534,000,000	$ 483,000,000
Equity method investments			$ 412,000,000					412,000,000	182,000,000
Impairment losses on investments								15,000,000	79,000,000	268,000,000
Emission Allowances
Asset Impairments
Impairment losses									20,000,000	0
Other
Asset Impairments
Impairment losses										29,000,000
Other Intangible Assets
Asset Impairments
Impairment losses										0
Solar Panels
Asset Impairments
Impairment losses							$ 0
Other Investments
Asset Impairments
Impairment losses										0
Renewables
Asset Impairments
Impairment losses									29,000,000
Construction in Progress
Asset Impairments
Impairment losses					$ 41,000,000
Construction in Progress, Gross					$ 0
Keystone
Asset Impairments
Ownership percentage	3.70%
Impairment losses on equity method investments	$ 14,000,000
Impairment losses on investments									35,000,000
Conemaugh
Asset Impairments
Impairment losses on equity method investments	$ 14,000,000
Impairment losses on investments									35,000,000
Dunkirk
Asset Impairments
Impairment losses on equity method investments				$ 46,000,000
Equity method investments				0
Other
Asset Impairments
Impairment losses on equity method investments				$ 15,000,000
Impairment losses on investments								$ 13,000,000	$ 10,000,000
South Texas Project
Asset Impairments
Impairment losses on investments			1,248,000,000
Indian River
Asset Impairments
Impairment losses on investments			$ 36,000,000
Petra Nova Parish Holdings
Asset Impairments
Ownership percentage			50.00%					50.00%				50.00%
Impairment losses on investments			$ 69,000,000			$ 140,000,000
Long Beach
Asset Impairments
Impairment losses							36,000,000
Community Wind North, LLC
Asset Impairments
Impairment losses on investments							36,000,000
Sherbino I Wind Farm LLC
Asset Impairments
Impairment losses on investments							$ 70,000,000
Rockford
Asset Impairments
Impairment losses										$ 17,000,000
Ownership percentage		100.00%
Proceeds from sale		$ 55,000,000
Held-for-sale \| NRG Solar Guam, LLC
Asset Impairments
Impairment losses			$ 12,000,000
Held-for-sale \| NRG Solar Guam, LLC \| Subsequent Event
Asset Impairments
Cash consideration											$ 8,000,000

Goodwill and Other Intangibles - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill and Other Intangibles
Goodwill	$ 573,000,000	$ 573,000,000	$ 539,000,000
Goodwill deductible for U.S. income tax purposes	366,000,000	366,000,000	460,000,000
Goodwill, Impairment Loss				$ 337,000,000	$ 1,400,000,000
Goodwill, Acquired During Period				1,700,000,000
Impairment		6,000,000	20,000,000
Emission allowances held-for-sale	12,000,000	12,000,000	9,000,000
Out-of-market contracts, net	121,000,000	121,000,000	129,000,000
Accumulated amortization, out of market contracts	37,000,000	37,000,000	29,000,000
Emission Allowances
Goodwill and Other Intangibles
Impairment		5,000,000	$ 20,000,000
Impairment related to power purchase agreements		0
Retail
Goodwill and Other Intangibles
Goodwill	408,000,000	408,000,000
Midwest Generation \| Lease Agreements
Goodwill and Other Intangibles
Out-of-market contracts, net	121,000,000	121,000,000
BETM \| Held-for-sale
Goodwill and Other Intangibles
Goodwill	21,000,000	21,000,000
Goodwill, Impairment Loss	90,000,000
EME Project Financings
Goodwill and Other Intangibles
Goodwill	$ 165,000,000	$ 165,000,000
Out-of-market contracts, net				$ 159,000,000

Goodwill and Other Intangibles - Components of Intangible Assets Subject to Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	$ 2,080	$ 2,162
Purchases	61	59
Acquisition of businesses(a)	178	18
Usage	(27)	(38)
Write-off of fully amortized balances	(528)	(77)
Impairment	(6)	(20)
Other	(16)	(24)
Balance at end of period	1,742	2,080
Less accumulated amortization	(1,151)	(1,573)
Net carrying amount	591	507
Emission Allowances
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	755	780
Purchases	33	27
Acquisition of businesses(a)	0	0
Usage	(1)	(10)
Write-off of fully amortized balances	(107)	0
Impairment	(5)	(20)
Other	(16)	(22)
Balance at end of period	659	755
Less accumulated amortization	(515)	(583)
Net carrying amount	144	172
Energy Supply
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	0	54
Purchases		0
Acquisition of businesses(a)		0
Usage		0
Write-off of fully amortized balances		(54)
Impairment		0
Other		0
Balance at end of period		0
Less accumulated amortization		0
Net carrying amount		0
Fuel
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	49	72
Purchases	0	0
Acquisition of businesses(a)	0	0
Usage	0	0
Write-off of fully amortized balances	0	(23)
Impairment	0	0
Other	0	0
Balance at end of period	49	49
Less accumulated amortization	(45)	(45)
Net carrying amount	4	4
Customer Contracts
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	1	1
Purchases	0	0
Acquisition of businesses(a)	0	0
Usage	0	0
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	0
Balance at end of period	1	1
Less accumulated amortization	(1)	(1)
Net carrying amount	0	0
Customer Relationships
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	768	750
Purchases	0	0
Acquisition of businesses(a)	122	18
Usage	0	0
Write-off of fully amortized balances	(411)	0
Impairment	(1)	0
Other	0	0
Balance at end of period	478	768
Less accumulated amortization	(314)	(693)
Net carrying amount	164	75
Marketing Partnerships
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	88	88
Purchases	0	0
Acquisition of businesses(a)	43	0
Usage	0	0
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	0
Balance at end of period	131	88
Less accumulated amortization	(61)	(54)
Net carrying amount	70	34
Trade Names
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	342	342
Purchases	0	0
Acquisition of businesses(a)	13	0
Usage	0	0
Write-off of fully amortized balances	(10)	0
Impairment	0	0
Other	0	0
Balance at end of period	345	342
Less accumulated amortization	(195)	(182)
Net carrying amount	150	160
Other
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	77	75
Purchases	28	32
Acquisition of businesses(a)	0	0
Usage	(26)	(28)
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	(2)
Balance at end of period	79	77
Less accumulated amortization	(20)	(15)
Net carrying amount	$ 59	$ 62

Goodwill and Other Intangibles - Schedule of Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	$ 107	$ 138	$ 157
Emission Allowances
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	39	71	62
Energy Supply
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	0	1	6
Fuel
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	0	1	1
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	32	34	48
Marketing Partnerships
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	9	5	8
Trade Names
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	23	23	23
Other
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	$ 4	$ 3	$ 9

Goodwill and Other Intangibles - Schedule of Estimated Amortization of Intangible Asset for the Next Five Years (Details) $ in Millions	Dec. 31, 2018 USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2019	$ 124
2020	116
2021	113
2022	110
2023	113
Emission Allowances
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2019	48
2020	37
2021	43
2022	50
2023	49
Fuel
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2019	0
2020	1
2021	0
2022	0
2023	1
Customer Relationships
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2019	38
2020	39
2021	33
2022	23
2023	26
Marketing Partnerships
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2019	11
2020	11
2021	10
2022	10
2023	10
Trade Names
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2019	24
2020	25
2021	24
2022	24
2023	24
Other
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2019	3
2020	3
2021	3
2022	3
2023	$ 3

Goodwill and Other Intangibles - Out of Market Contracts (Details) - Out of Market Contracts - Lease Agreements $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Out of Market Contracts Five Year Maturity
2019	$ 8
2020	8
2021	8
2022	8
2023	$ 8

Debt and Capital Leases - Schedule of Long-term Debt and Capital Leases (Details) - USD ($) $ in Millions				12 Months Ended
	Mar. 21, 2018	Jan. 24, 2017	Jun. 30, 2016	Dec. 31, 2018	Nov. 05, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2017	Dec. 07, 2017
Debt Instrument [Line Items]
Long-term debt				$ 6,691				$ 9,494
Capital leases				1				5
Subtotal				6,692				9,499
Less current maturities				(72)				(204)
Less debt issuance costs				(70)				(103)
Discounts				(101)				(12)
Total long-term debt and capital leases				6,449				9,180
Debt Instrument, Unamortized Discount [Abstract]
Total discounts				(101)				(12)
Recourse Debt
Debt Instrument [Line Items]
Long-term debt				6,523				7,182
Recourse Debt \| Senior notes, due 2022
Debt Instrument [Line Items]
Long-term debt				$ 0				992
Interest rate, stated percentage				6.25%		6.25%	6.25%
Recourse Debt \| Senior notes, due 2024
Debt Instrument [Line Items]
Long-term debt				$ 733				733
Interest rate, stated percentage				6.25%		6.25%
Recourse Debt \| Senior notes, due 2026
Debt Instrument [Line Items]
Long-term debt				$ 1,000				1,000
Interest rate, stated percentage				7.25%		7.25%
Recourse Debt \| Senior notes, due 2027
Debt Instrument [Line Items]
Long-term debt				$ 1,230				1,250
Interest rate, stated percentage				6.625%		6.625%
Recourse Debt \| Senior notes, due 2028
Debt Instrument [Line Items]
Long-term debt				$ 821				870
Interest rate, stated percentage				5.75%		5.75%	5.75%		5.75%
Recourse Debt \| Convertible Senior Notes, due 2048
Debt Instrument [Line Items]
Long-term debt				$ 575				0
Interest rate, stated percentage						2.75%
Debt Instrument, Unamortized Discount [Abstract]
Unamortized discount on debt instruments				(96)				0
Recourse Debt \| Term loan facility, due 2023
Debt Instrument [Line Items]
Long-term debt			$ 1,900	1,698	$ 260			1,872
Debt Instrument, Unamortized Discount [Abstract]
Unamortized discount on debt instruments				$ (4)				(7)
Recourse Debt \| Term loan facility, due 2023 \| LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.75%	2.25%	2.75%	1.75%
Recourse Debt \| Tax-exempt bonds
Debt Instrument [Line Items]
Long-term debt				$ 466				465
Recourse Debt \| Tax-exempt bonds \| Low
Debt Instrument [Line Items]
Interest rate, stated percentage				4.125%
Recourse Debt \| Tax-exempt bonds \| Maximum
Debt Instrument [Line Items]
Interest rate, stated percentage				6.00%
Non Recourse Debt
Debt Instrument [Line Items]
Long-term debt				$ 168				2,312
Non Recourse Debt \| Ivanpah, due 2033 and 2038
Debt Instrument [Line Items]
Long-term debt				$ 0				1,073
Non Recourse Debt \| Ivanpah, due 2033 and 2038 \| Low
Debt Instrument [Line Items]
Interest rate, stated percentage				2.285%
Non Recourse Debt \| Ivanpah, due 2033 and 2038 \| Maximum
Debt Instrument [Line Items]
Interest rate, stated percentage				4.256%
Non Recourse Debt \| Agua Caliente, due 2037
Debt Instrument [Line Items]
Long-term debt				$ 0				818
Non Recourse Debt \| Agua Caliente, due 2037 \| Low
Debt Instrument [Line Items]
Interest rate, stated percentage				2.395%
Non Recourse Debt \| Agua Caliente, due 2037 \| Maximum
Debt Instrument [Line Items]
Interest rate, stated percentage				3.633%
Non Recourse Debt \| Agua Caliente Borrower 1, due 2038
Debt Instrument [Line Items]
Long-term debt				$ 86				89
Interest rate, stated percentage						5.43%
Non Recourse Debt \| Midwest Generation, due 2019
Debt Instrument [Line Items]
Long-term debt				48				152
Interest rate, stated percentage						4.39%
Debt Instrument, Unamortized Discount [Abstract]
Unamortized discount on debt instruments				(1)				(5)
Non Recourse Debt \| NRG Other
Debt Instrument [Line Items]
Long-term debt				$ 34				$ 180

Debt and Capital Leases - Annual Payments Based on the Maturities of Debt and Capital Leases (Details) $ in Millions	Dec. 31, 2018 USD ($)
Debt Disclosure [Abstract]
2019	$ 74
2020	26
2021	27
2022	25
2023	1,635
Thereafter	4,905
Total	$ 6,692

Debt and Capital Leases - Issuance of Convertible Senior Notes (Details)	3 Months Ended
	Jun. 30, 2018 USD ($) $ / shares
Debt Instrument [Line Items]
Debt issuance transaction costs	$ 12,000,000
Convertible Senior Notes, due 2048 \| Convertible Debt
Debt Instrument [Line Items]
Aggregate principal amount	$ 575,000,000
Interest rate, stated percentage	2.75%
Conversion price per common share (in usd per share) \| $ / shares	$ 47.74
Conversion ratio	20.9479
Debt, estimated fair value	$ 472,000,000
Carrying amount of equity component	$ 103,000,000
Debt discount amortization period	7 years
Debt deferred financing costs amortization period	7 years
Convertible Senior Notes, due 2048 \| Convertible Debt \| Deferred Financing Costs
Debt Instrument [Line Items]
Debt issuance transaction costs	$ 10,000,000
Convertible Senior Notes, due 2048 \| Convertible Debt \| Additional Paid-in Capita
Debt Instrument [Line Items]
Debt issuance transaction costs	$ 2,000,000

Debt and Capital Leases - Issuance of Senior Notes (Details) - Recourse Debt - USD ($) $ in Millions	Dec. 07, 2017	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
Senior Notes due 2028
Debt Instrument [Line Items]
Proceeds from issuance of senior notes	$ 870
Interest rate, stated percentage	5.75%	5.75%	5.75%	5.75%
Senior Notes, due 2023
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%				6.625%

Debt and Capital Leases - Senior Notes Repurchases (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 07, 2017
Debt Instrument [Line Items]
Loss on debt extinguishment				$ 44	$ 49	$ 142
Senior Notes
Debt Instrument [Line Items]
Loss on debt extinguishment				38
Write off of deferred debt issuance cost				7
Recourse Debt \| Senior Notes
Debt Instrument [Line Items]
Loss on debt extinguishment					49
Write off of deferred debt issuance cost					7
Principal Repurchased	$ 1,061	$ 576	$ 43	1,061	1,473
Cash Paid	1,106	$ 598	$ 45	$ 1,106	$ 1,544
Average Early Redemption Percentage				25.00%
Accrued interest	$ 14			$ 14
Recourse Debt \| Senior notes, due 2028
Debt Instrument [Line Items]
Interest rate, stated percentage	5.75%	5.75%	5.75%	5.75%			5.75%
Principal Repurchased		$ 20	$ 29
Cash Paid		$ 20	$ 30
Average Early Redemption Percentage		99.13%	99.24%
Recourse Debt \| Senior notes, due 2022
Debt Instrument [Line Items]
Interest rate, stated percentage	6.25%	6.25%	6.25%	6.25%
Principal Repurchased	$ 485	$ 493	$ 14	$ 485
Cash Paid	$ 508	$ 512	$ 15	$ 508
Average Early Redemption Percentage	103.125%	103.13%	103.25%
Recourse Debt \| Senior notes, due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%	6.625%		6.625%
Principal Repurchased		$ 20
Cash Paid		$ 21
Average Early Redemption Percentage		103.06%

Debt and Capital Leases - Senior Note Redemptions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Jun. 30, 2018	Dec. 07, 2017
Debt Instrument [Line Items]
Loss on debt extinguishment	$ 44	$ 49	$ 142
Senior notes
Debt Instrument [Line Items]
Loss on debt extinguishment	38
Write off of deferred debt issuance cost	7
Recourse Debt \| Senior notes
Debt Instrument [Line Items]
Principal amount redeemed		1,500
Loss on debt extinguishment		49
Write off of deferred debt issuance cost		7
Principal Repurchased	1,061	1,473		$ 576	$ 43
Cash Paid	$ 1,106	1,544		$ 598	$ 45
Average Early Redemption Percentage	25.00%
Accrued interest		$ 29
Recourse Debt \| Senior notes, due 2018
Debt Instrument [Line Items]
Interest rate, stated percentage		7.625%
Principal Repurchased		$ 398
Cash Paid		$ 411
Average Early Redemption Percentage		101.42%
Recourse Debt \| Senior notes, due 2021
Debt Instrument [Line Items]
Interest rate, stated percentage		7.875%
Principal Repurchased		$ 206
Cash Paid		$ 218
Average Early Redemption Percentage		102.63%
Recourse Debt \| Senior notes, due 2023
Debt Instrument [Line Items]
Interest rate, stated percentage		6.625%				6.625%
Principal Repurchased		$ 869
Cash Paid		$ 915
Average Early Redemption Percentage		103.57%

Debt and Capital Leases - Senior Notes Outstanding (Details) - Recourse Debt	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 07, 2017
Senior Notes 2024
Debt Instrument [Line Items]
Interest rate, stated percentage	6.25%	6.25%
Senior Notes due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage	7.25%	7.25%
Senior Notes due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%	6.625%
Senior Notes due 2028
Debt Instrument [Line Items]
Interest rate, stated percentage	5.75%	5.75%	5.75%	5.75%

Debt and Capital Leases - Recourse Debt Redemption Period (Details) - Recourse Debt	3 Months Ended		12 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2018
Senior Notes
Debt Instrument [Line Items]
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.
Average Early Redemption Percentage			25.00%
Senior Notes 2024
Debt Instrument [Line Items]
Average Early Redemption Percentage			35.00%
Senior Notes 2024 \| Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)			0.50%
Premium percentage of principal amount of note discount factor (as percent)			1.00%
Senior Notes due 2026
Debt Instrument [Line Items]
Average Early Redemption Percentage			35.00%
Senior Notes due 2026 \| Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)			0.50%
Premium percentage of principal amount of note discount factor (as percent)			1.00%
Senior Notes due 2027
Debt Instrument [Line Items]
Average Early Redemption Percentage	103.06%
Redemption percentage			35.00%
Senior Notes due 2027 \| Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)			0.50%
Premium percentage of principal amount of note discount factor (as percent)			1.00%
Senior Notes due 2028
Debt Instrument [Line Items]
Average Early Redemption Percentage	99.13%	99.24%
Redemption percentage			35.00%
Senior Notes due 2028 \| Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)			0.50%
Premium percentage of principal amount of note discount factor (as percent)			1.00%
May 1, 2019 to April 30, 2020 \| Senior Notes 2024
Debt Instrument [Line Items]
Redemption percentage			103.125%
May 1, 2020 to April 30, 2021 \| Senior Notes 2024
Debt Instrument [Line Items]
Redemption percentage			102.083%
May 1, 2021 to April 30, 2022 \| Senior Notes 2024
Debt Instrument [Line Items]
Redemption percentage			101.042%
May 1, 2022 and thereafter \| Senior Notes 2024
Debt Instrument [Line Items]
Redemption percentage			100.00%
Redemption Period prior to 1 May 2019 \| Senior Notes 2024
Debt Instrument [Line Items]
Redemption description			At any time prior to May 1, 2019, NRG may redeem up to 35% of the aggregate principal amount 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			106.25%
Present value of note(as percentage)			1.03125
Redemption Period Prior To 1 May 2019 \| Senior Notes 2024
Debt Instrument [Line Items]
Redemption percentage			100.00%
Redemption Period Prior to 15 May 2019 \| Senior Notes due 2026
Debt Instrument [Line Items]
Redemption description			At any time prior to May 15, 2019, NRG may redeem up to 35% of the aggregate principal amount of the 2026 Senior Notes, at a redemption price equal to 107.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings
Redemption percentage			107.25%
Redemption Period Prior To 15 May 2021 \| Senior Notes due 2026
Debt Instrument [Line Items]
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 [Line Items]
Redemption percentage			103.625%
May 15, 2022 to May 14, 2023 \| Senior Notes due 2026
Debt Instrument [Line Items]
Redemption percentage			102.417%
May 15, 2023 to May 14, 2024 \| Senior Notes due 2026
Debt Instrument [Line Items]
Redemption percentage			101.208%
May 15, 2024 and thereafter \| Senior Notes due 2026
Debt Instrument [Line Items]
Redemption percentage			100.00%
Redemption Period Prior To 15 July 2019 \| Senior Notes due 2027
Debt Instrument [Line Items]
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 percentage			106.625%
Redemption Period Prior To 15 July 2021 \| Senior Notes due 2027
Debt Instrument [Line Items]
Redemption description			At any time prior to July 15, 2021 NRG may redeem all or a part of the 2027 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on the note from the date of redemption through July 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%.
Redemption percentage			100.00%
Present value of note(as percentage)			1.03313
July 15, 2021 to July14, 2022 \| Senior Notes due 2027
Debt Instrument [Line Items]
Redemption percentage			103.313%
July 15, 2022 to July 14, 2023 \| Senior Notes due 2027
Debt Instrument [Line Items]
Redemption percentage			102.208%
July 15, 2023 to July 14, 2024 \| Senior Notes due 2027
Debt Instrument [Line Items]
Redemption percentage			101.104%
July 15, 2024 and thereafter \| Senior Notes due 2027
Debt Instrument [Line Items]
Redemption percentage			100.00%
Redemption Period Prior to January 15, 2021 \| Senior Notes due 2028
Debt Instrument [Line Items]
Redemption percentage			105.75%
Redemption Period Prior to January 15, 2023 \| Senior Notes due 2028
Debt Instrument [Line Items]
Redemption percentage			100.00%
Present value of note(as percentage)			1.02875
January 15, 2023 to January 14, 2024 \| Senior Notes due 2028
Debt Instrument [Line Items]
Redemption percentage			102.875%
January 15, 2024 to January 14, 2025 \| Senior Notes due 2028
Debt Instrument [Line Items]
Redemption percentage			101.917%
January 15, 2025 to January 14, 2026 \| Senior Notes due 2028
Debt Instrument [Line Items]
Redemption percentage			100.958%
January 15, 2026 and thereafter \| Senior Notes due 2028
Debt Instrument [Line Items]
Redemption percentage			100.00%

Debt and Capital Leases - Senior Credit Facility and Tax Exempt Bonds (Details)					12 Months Ended
	Nov. 05, 2018 USD ($)	Mar. 21, 2018	Jan. 24, 2017	Jun. 30, 2016 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Debt Instrument [Line Items]
Long-term debt					$ 6,691,000,000	$ 9,494,000,000
Loss on debt extinguishment					44,000,000	49,000,000	$ 142,000,000
Recourse Debt
Debt Instrument [Line Items]
Long-term debt					6,523,000,000	7,182,000,000
Recourse Debt \| Term loan facility, due 2023
Debt Instrument [Line Items]
Long-term debt	$ 260,000,000			$ 1,900,000,000	$ 1,698,000,000	1,872,000,000
Percent of face value				99.50%
Periodic payment, percentage of principal				0.0025
Prepaid amount	155,000,000
Loss on debt extinguishment	3,000,000
Write off of deferred debt issuance cost	2,000,000
Recourse Debt \| Term loan facility, due 2023 \| LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		1.75%	2.25%	2.75%	1.75%
Decrease in interest rate margin		50.00%	50.00%
Recourse Debt \| Term loan facility, due 2023 \| LIBOR floor
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		0.00%	0.75%	0.75%
Recourse Debt \| Indian River Power, tax exempt bonds, due 2040
Debt Instrument [Line Items]
Long-term debt					$ 57,000,000	57,000,000
Interest rate, stated percentage					6.00%
Recourse Debt \| Indian River Power LLC, tax exempt bonds, due 2045
Debt Instrument [Line Items]
Long-term debt					$ 190,000,000	190,000,000
Interest rate, stated percentage					5.375%
Recourse Debt \| Dunkirk Power LLC, tax exempt bonds, due 2042
Debt Instrument [Line Items]
Long-term debt					$ 59,000,000	59,000,000
Interest rate, stated percentage					5.875%
Recourse Debt \| City of Texas City, tax exempt bonds, due 2045
Debt Instrument [Line Items]
Long-term debt					$ 33,000,000	32,000,000
Interest rate, stated percentage					4.125%
Recourse Debt \| Fort Bend County, tax exempt bonds, due 2038
Debt Instrument [Line Items]
Long-term debt					$ 54,000,000	54,000,000
Interest rate, stated percentage					4.75%
Recourse Debt \| Fort Bend County, tax exempt bonds, due 2042
Debt Instrument [Line Items]
Long-term debt					$ 73,000,000	73,000,000
Interest rate, stated percentage					4.75%
Recourse Debt \| Tax-exempt bonds
Debt Instrument [Line Items]
Long-term debt					$ 466,000,000	$ 465,000,000
Senior Credit Facility \| Term loan facility, due 2023
Debt Instrument [Line Items]
Long-term debt	$ 105,000,000
Revolving Credit Facility \| 2016 Tranche A Revolving Credit Facility due 2018
Debt Instrument [Line Items]
Revolving credit facility				$ 289,000,000
Revolving Credit Facility \| 2016 Tranche B Revolving Credit Facility due 2021
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)				2.25%
Revolving credit facility				$ 2,200,000,000.0

Debt and Capital Leases - Midwest Generation (Details) - USD ($) $ in Millions	Apr. 07, 2016	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term debt		$ 6,691		$ 9,494
Non Recourse Debt
Debt Instrument [Line Items]
Long-term debt		168		2,312
Non Recourse Debt \| Midwest Generation, due 2019
Debt Instrument [Line Items]
Interest rate, stated percentage			4.39%
Long-term debt		$ 48		$ 152
Midwest Generation \| Non Recourse Debt
Debt Instrument [Line Items]
Proceeds from sale of unforced capacity	$ 253
Interest rate, stated percentage	4.39%

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Nuclear decommissioning ARO liabilities	$ 282	$ 269
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at the beginning of the period	679
Revisions in estimates for current obligations	(27)
Additions	9
Spending for current obligations	(27)
Accretion — Expense	30
Accretion — Nuclear decommissioning	15
Balance at the ending of the period	$ 679

Benefit Plans and Other Postretirement Benefits - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2017
GenOn
Benefit Plans and Other Postretirement Benefits
Pension liability retained	$ 92
Liability retained other post-employment and retiree health and welfare benefits	25
Restructuring Support Agreement \| GenOn
Benefit Plans and Other Postretirement Benefits
Amount of pension liability future contributions			$ 13
Expects to contribute to the pension plans	13
Pension Benefits \| Scenario, Plan
Benefit Plans and Other Postretirement Benefits
Expects to contribute to the pension plans	41
Pension Benefits \| GenOn
Benefit Plans and Other Postretirement Benefits
Liability retained other post-employment and retiree health and welfare benefits	$ 0	$ 0

Benefit Plans and Other Postretirement Benefits - Net Benefit Costs and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 14, 2018	Dec. 31, 2017	Jun. 14, 2017
Annual periodic pension cost
Curtailment gain			$ 80
GenOn
Fair value of plan assets for pension and other post retirement benefit
Add: Retained obligation in bankruptcy proceeding				$ (25)
Pension liability retained				92
Pension Benefits
Annual periodic pension cost
Service cost benefits earned	$ 23	$ 26	30
Interest cost on benefit obligation	44	43	43
Expected return on plan assets	(62)	(58)	(60)
Amortization of unrecognized net loss	0	4	2
Curtailment gain	7	0	0
Net recognized in net periodic pension cost/(credit) and OCI	49	(11)
Net periodic benefit cost			15
Pension and other post retirement benefit obligations
Benefit obligation at January 1	1,329	1,241
Service cost	23	26	30
Interest cost	44	43	43
Plan amendments	17	0
Actuarial (gain)/loss	(95)	77
Employee and retiree contributions	0	0
Curtailment gain	(20)	0
Benefit payments	(76)	(58)
Benefit obligation at December 31	1,222	1,329	1,241
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1	1,104	953
Actual return on plan assets	(80)	173
Employee and retiree contributions	0	0
Employer contributions	33	36
Benefit payments	(76)	(58)
Fair value of plan assets at December 31	981	1,104	953
Funded status at December 31 — excess of obligation over assets				(241)		$ (225)
Less: GenOn postretirement obligation	1,329	1,241	1,241	1,222		1,329
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				(241)		(225)
Other Postretirement Benefit
Annual periodic pension cost
Service cost benefits earned	1	1	2
Interest cost on benefit obligation	4	4	6
Amortization of unrecognized prior service credit	(10)	(9)	(5)
Amortization of unrecognized net loss	0	(1)	0
Curtailment gain	(10)	0	0
Net recognized in net periodic pension cost/(credit) and OCI	(36)	13
Net periodic benefit cost			3
Pension and other post retirement benefit obligations
Benefit obligation at January 1	128	128
Service cost	1	1	2
Interest cost	4	4	6
Plan amendments	(28)	(1)
Actuarial (gain)/loss	(6)	6
Employee and retiree contributions	3	3
Curtailment gain	(7)	0
Benefit payments	(12)	(13)
Benefit obligation at December 31	83	128	128
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	9	10
Benefit payments	(12)	(13)
Fair value of plan assets at December 31	0	0	0
Funded status at December 31 — excess of obligation over assets				(83)		(128)
Less: GenOn postretirement obligation	128	128	$ 128	83		128
Other Postretirement Benefit \| GenOn
Pension and other post retirement benefit obligations
Benefit obligation at January 1	38
Benefit obligation at December 31	0	38
Fair value of plan assets for pension and other post retirement benefit
Less: GenOn postretirement obligation	$ 38	$ 38		0	$ 23	38
Add: Retained obligation in bankruptcy proceeding				0		(25)	$ (25)
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				$ (83)		$ (115)

Benefit Plans and Other Postretirement Benefits - Amounts Recognized in the Balance Sheets and OCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 14, 2018	Jun. 14, 2017
Pension Benefits
Amounts recognized in balance sheet
Current liabilities	$ 0	$ 0
Non-current liabilities	241	225
Amounts recognized in accumulated OCI
Net loss/(gain)	90	53
Prior service cost/(credit)	3	3
Total accumulated OCI	93	56
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial loss/(gain)	47	(37)
Amortization of net actuarial (gain)/loss	0	(4)	$ (2)
Curtailment	(27)	0
Prior service credit	17	0
Amortization of prior service cost	0	0
Total recognized in other comprehensive loss	37	(41)
Net recognized in net periodic pension cost/(credit) and OCI	49	(11)
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)	4
Significant components of NRG's domestic pension plan
Projected benefit obligation	1,222	1,329	1,241
Accumulated benefit obligation	1,188	1,255
Fair value of plan assets	981	1,104	953
Other Postretirement Benefit
Amounts recognized in balance sheet
Current liabilities	7	7
Non-current liabilities	76	121
Amounts recognized in accumulated OCI
Net loss/(gain)	(9)	(4)
Prior service cost/(credit)	(53)	(37)
Total accumulated OCI	(62)	(41)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial loss/(gain)	(5)	6
Amortization of net actuarial (gain)/loss	0	1	0
Curtailment	2	0
Prior service credit	(28)	(1)
Amortization of prior service cost	10	9
Total recognized in other comprehensive loss	(21)	15
Net recognized in net periodic pension cost/(credit) and OCI	(36)	13
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		13
Significant components of NRG's domestic pension plan
Projected benefit obligation	83	128	128
Fair value of plan assets	0	0	$ 0
GenOn
Amounts recognized in balance sheet
Pension benefit obligations	92
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	0	3
Non-current liabilities	0	10
Liability retained other post-employment and retiree health and welfare benefits	0	25			$ 25
Significant components of NRG's domestic pension plan
Projected benefit obligation	0	38		$ 23
NRG \| Pension Benefits
Amounts recognized in balance sheet
Current liabilities	0	0
Non-current liabilities	241	225
NRG \| Other Postretirement Benefit
Amounts recognized in balance sheet
Current liabilities	7	4
Non-current liabilities	76	111
Discontinued Operations \| Pension Benefits
Amounts recognized in accumulated OCI
Total accumulated OCI	0	(22)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Total recognized in other comprehensive loss	0	15
Net recognized in net periodic pension cost/(credit) and OCI	0	0
Discontinued Operations \| Other Postretirement Benefit
Amounts recognized in accumulated OCI
Total accumulated OCI	0	10
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Total recognized in other comprehensive loss	0	2
Net recognized in net periodic pension cost/(credit) and OCI	0	1
Continuing Operations \| Pension Benefits
Amounts recognized in accumulated OCI
Total accumulated OCI	93	34
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Total recognized in other comprehensive loss	37	(26)
Net recognized in net periodic pension cost/(credit) and OCI	12	15
Continuing Operations \| Other Postretirement Benefit
Amounts recognized in accumulated OCI
Total accumulated OCI	(62)	(31)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Total recognized in other comprehensive loss	(21)	17
Net recognized in net periodic pension cost/(credit) and OCI	$ (15)	$ (5)

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Minimum
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	$ 981	$ 1,104	$ 953
Significant assumptions used to calculate NRG's benefit obligations
Discount rate	4.38%	3.71%
Rate of compensation increase	3.00%	3.00%
Significant assumptions used to calculate NRG's benefit expense
Discount rate		4.26%	4.52%
Expected return on plan assets	6.17%	6.85%	6.65%
Rate of compensation increase	3.00%	3.00%	3.00%
Pension Benefits \| Minimum
Significant assumptions used to calculate NRG's benefit expense
Discount rate		3.71%
Pension Benefits \| Maximum
Significant assumptions used to calculate NRG's benefit expense
Discount rate		4.04%
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	4.37%	3.71%
Rate of compensation increase	0.00%
Significant assumptions used to calculate NRG's benefit expense
Discount rate		4.29%	4.55%
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	7.80%	8.20%
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%	4.50%
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	8.20%	7.00%	7.25%
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	4.50%	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	$ 621	$ 735
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	183	256
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	53	66
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	117	178
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	256	230
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	12	5
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	12	5
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	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	12	5
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	609	730
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	183	256
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	53	66
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	117	178
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	256	230
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	70	94
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	249	233
Measured at net asset value practical expedient \| Partnerships/joint ventures \| Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	25	42
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, 2018	Dec. 31, 2017	Dec. 31, 2016
One-percentage-point change in assumed health care cost trend rates
Effect on postretirement benefit obligation, 1-Percentage-Point Increase	$ 5
Effect on postretirement benefit obligation, 1-Percentage-Point Decrease	(4)
Company's contributions to 401(k) plans
Company contributions to defined contribution plans	$ 28	$ 56	$ 55
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	$ 13	8
Expected reimbursement of contribution to retirement plan obligations to STPNOC in 2014	18
Pension Benefit Payments
NRG's expected future benefit payments
2019	72
2020	76
2021	79
2022	82
2023	85
2024-2028	418
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(241)	(225)
Net periodic benefit costs			15
Total recognized in other comprehensive loss	(37)	41
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	(78)	(76)
Net periodic benefit costs	8	8
Total recognized in other comprehensive loss	(7)	(6)
Other Postretirement Benefit
NRG's expected future benefit payments
2019	7
2020	7
2021	7
2022	6
2023	6
2024-2028	26
Medicare prescription drug reimbursements
2019	0
2020	0
2021	0
2022	0
2023	0
2024-2028	1
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(83)	(128)
Net periodic benefit costs			$ 3
Total recognized in other comprehensive loss	21	(15)
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	(19)	(24)
Net periodic benefit costs	(7)	(3)
Total recognized in other comprehensive loss	$ 2	$ 5

Capital Structure - Changes in Common Shares issued and Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2018	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)	418,323,134
Beginning balance, treasury shares(in shares)	(101,580,045)
Beginning balance, common shares outstanding (in shares)	316,743,089
Share repurchases (in shares)	(35,234,664)
Ending balance, common shares issued (in shares)	420,288,886	418,323,134
Ending balance, treasury shares (in shares)	(136,638,847)	(101,580,045)
Ending balance, common shares outstanding (in shares)	283,650,039	316,743,089
Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued (in shares)	418,323,134	417,583,825	416,939,950
Beginning balance, common shares outstanding (in shares)	316,743,089	315,443,011	314,190,042
Shares issued under ESPP (in shares)	175,862	560,769	609,094
Shares issued from LTIP (in shares)	1,965,752	739,309	643,875
Ending balance, common shares issued (in shares)	420,288,886	418,323,134	417,583,825
Ending balance, common shares outstanding (in shares)	283,650,039	316,743,089	315,443,011
Treasury Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, treasury shares(in shares)	(101,580,045)	(102,140,814)	(102,749,908)
Shares issued under ESPP (in shares)	175,862	560,769	609,094
Shares issued from LTIP (in shares)	0	0	0
Share repurchases (in shares)	(35,234,664)
Ending balance, treasury shares (in shares)	(136,638,847)	(101,580,045)	(102,140,814)

Capital Structure - Common Stock (Details) - USD ($)				3 Months Ended	12 Months Ended			33 Months Ended
Capital Structure - Common Stock (Details) - USD ($)	Feb. 15, 2019	Feb. 01, 2019	Jan. 23, 2019	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Feb. 28, 2019
Common Stock, Employee Stock Purchase Plan and Share Repurchases
Dividends paid per share (in usd per share)				$ 0.145				$ 0.030
Common stock dividends, proposed annual percentage decrease							79.00%
Dividends per common share (in usd per share)					$ 0.12	$ 0.12	$ 0.24
Eligible compensation withholding, up to (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)					2,931,188			2,931,188
Capital Allocation Plan
Common Stock, Employee Stock Purchase Plan and Share Repurchases
Stock repurchase program, authorized amount					$ 1,500,000,000.0			$ 1,500,000,000.0
Subsequent Event
Common Stock, Employee Stock Purchase Plan and Share Repurchases
Dividends payable, date declared			Jan. 23, 2019
Dividends per common share (in usd per share)			$ 0.00030
Dividends payable, date to be paid	Feb. 15, 2019
Dividends payable, date of record		Feb. 01, 2019
Subsequent Event \| Capital Allocation Plan
Common Stock, Employee Stock Purchase Plan and Share Repurchases
Stock repurchase program, authorized amount									$ 1,000,000,000
Scenario, Plan
Common Stock, Employee Stock Purchase Plan and Share Repurchases
Common stock, dividends, proposed annual amount, per share				$ 0.58			$ 0.0012
Scenario, Plan \| Subsequent Event
Common Stock, Employee Stock Purchase Plan and Share Repurchases
Common stock, dividends, proposed annual amount, per share			$ 0.0012
Long-term incentive plans
Common Stock, Employee Stock Purchase Plan and Share Repurchases
Long-term incentive plans (in shares)					17,631,031			17,631,031

Capital Structure - Summary of Changes in Shares Repurchased (Details) - USD ($) $ / shares in Units, $ in Millions	2 Months Ended	12 Months Ended	14 Months Ended
	Feb. 28, 2019	Dec. 31, 2018	Feb. 28, 2019
Capital Allocation Plan [Line Items]
Total number of shares purchased (in shares)		35,234,664
Capital Allocation Plan, Open Market Repurchases
Capital Allocation Plan [Line Items]
Total number of shares purchased (in shares)		11,097,631,000,000
Amounts paid for shares purchased (in millions)		$ 396
Capital Allocation Plan, Accelerated Repurchase Agreement May 2018
Capital Allocation Plan [Line Items]
Total number of shares purchased (in shares)		10,829,903,000,000
Amounts paid for shares purchased (in millions)		$ 354
Capital Allocation Plan, Accelerated Repurchase Program September 2018
Capital Allocation Plan [Line Items]
Total number of shares purchased (in shares)		13,307,130,000,000
Amounts paid for shares purchased (in millions)		$ 500
Capital Allocation Plan
Capital Allocation Plan [Line Items]
Total number of shares purchased (in shares)		35,234,664,000,000
Amounts paid for shares purchased (in millions)		$ 1,250
Subsequent Event \| Capital Allocation Plan, Open Market Repurchases
Capital Allocation Plan [Line Items]
Total number of shares purchased (in shares)	6,153,415,000,000
Amounts paid for shares purchased (in millions)	$ 250
Subsequent Event \| Capital Allocation Plan
Capital Allocation Plan [Line Items]
Total number of shares purchased (in shares)			41,388,079,000,000
Average price paid per share (in shares)			$ 36.24
Amounts paid for shares purchased (in millions)			$ 1,500

Capital Structure - Preferred Stock (Details) - USD ($) $ in Millions			12 Months Ended
	Jun. 13, 2016	May 24, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capital Structure
Redemption of shares (as percentage)	100.00%	100.00%
Preferred shares repurchased		$ 345
Repurchase of outstanding shares			$ 0	$ 0	$ 226
Gain on redemption of preferred shares			0	0	78
Carrying value of preferred stock at time of redemption			$ 0	$ 0	$ 0	$ 302
Convertible Preferred Stock
Capital Structure
Preferred stock, dividend rate (as percent)		2.822%	2.822%	2.822%	2.822%
Repurchase of outstanding shares	$ 226
Gain on redemption of preferred shares	78
Carrying value of preferred stock at time of redemption	$ 304

Capital Structure - Changes in Redeemable Preferred Stock (Details) - USD ($) $ in Millions			12 Months Ended
	Jun. 13, 2016	May 24, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Temporary Equity [Roll Forward]
Balance at beginning of period			$ 0	$ 0	$ 302
Accretion to redemption value					2
Repurchase of 2.822% redeemable preferred stock			0	0	(226)
Gain on redemption of 2.822% redeemable preferred stock			0	0	78
Balance at end of period			$ 0	$ 0	$ 0
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, 2018	Dec. 31, 2017
Investments Accounted for by the Equity Method
Equity investments in affiliates	$ 412	$ 182
Undistributed earnings by equity investment	$ 34	$ 38
Agua Caliente
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	35.00%
Equity investments in affiliates	$ 200
Gladstone
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	37.50%
Equity investments in affiliates	$ 140
Ivanpah Master Holdings, LLC
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	54.50%
Equity investments in affiliates	$ 37
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	$ 17
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	$ 12
Other
Investments Accounted for by the Equity Method
Equity investments in affiliates	$ 6

Investments Accounted for by the Equity Method and Variable Interest Entities - Variable Interest Entities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) project MW	Dec. 31, 2017 USD ($)
Schedule of Equity Method Investments [Line Items]
Generation capacity (in MW) \| MW	23,000
Equity investments in affiliates	$ 412	$ 182
Ivanpah Master Holdings LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage	54.50%
Number of solar electric generating projects \| project	3
Generation capacity (in MW) \| MW	393
Release of reserves to fund equity distributions	$ 95
Loss on deconsolidation	22
Reduction of assets due to deconsolidation	1,300
Reduction of liabilities due to deconsolidation	1,200
Equity investments in affiliates	$ 37
Gladstone
Schedule of Equity Method Investments [Line Items]
Ownership percentage	37.50%
Generation capacity (in MW) \| MW	1,613
Equity investments in affiliates	$ 140

Investments Accounted for by the Equity Method and Variable Interest Entities - Other Equity Investments (Details) $ in Millions	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)
Schedule of Equity Method Investments [Line Items]
Generation capacity (in MW) \| MW	23,000
Equity investments in affiliates	$ 412	$ 182
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	3	6
Net property, plant and equipment	76	80
Other long-term assets	28	36
Total assets	107	122
Current liabilities	2	3
Long-term debt	29	30
Other long-term liabilities	7	7
Total liabilities	38	40
Redeemable noncontrolling interests	19	19
Net assets less noncontrolling interests	$ 50	$ 63
Gladstone
Schedule of Equity Method Investments [Line Items]
Ownership percentage	37.50%
Generation capacity (in MW) \| MW	1,613
Equity investments in affiliates	$ 140

Earnings /Loss Per Share (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended								12 Months Ended
	Jun. 13, 2016	May 24, 2016	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Redemption of shares (as percentage)	100.00%	100.00%
Basic income/(loss) per share attributable to NRG common stockholders
Net Income/(Loss) Attributable to NRG Energy, Inc.											$ 268	$ (2,153)	$ (774)
Dividends for preferred shares											0	0	5
Gain on redemption of preferred shares											0	0	(78)
Income/(Loss) Available for Common Stockholders			$ (11)	$ (72)	$ 72	$ 279	$ (1,535)	$ 171	$ (626)	$ (163)	$ 268	$ (2,153)	$ (701)
Weighted average number of common shares outstanding — basic (in shares)			289,000,000	299,000,000	310,000,000	318,000,000	317,000,000	317,000,000	316,000,000	316,000,000	304,000,000	317,000,000	316,000,000
Income/(Loss) per weighted average common share — basic (in usd per share)			$ (0.04)	$ (0.24)	$ 0.23	$ 0.88	$ (4.84)	$ 0.54	$ (1.98)	$ (0.52)	$ 0.88	$ (6.79)	$ (2.22)
Incremental shares attributable to the issuance of equity compensation (treasury stock method) (in shares)											4,000,000	0	0
Weighted average number of common shares outstanding — diluted (in shares)			289,000,000	299,000,000	314,000,000	322,000,000	317,000,000	322,000,000	316,000,000	316,000,000	308,000,000	317,000,000	316,000,000
Income (Loss) per weighted average common share — diluted (in usd per share)			$ (0.04)	$ (0.24)	$ 0.23	$ 0.87	$ (4.84)	$ 0.53	$ (1.98)	$ (0.52)	$ 0.87	$ (6.79)	$ (2.22)
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 income/(loss) per share attributable to NRG common stockholders
Gain on redemption of preferred shares	$ (78)

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
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	7	5	5
Stock Compensation Plan
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	0	5	5
Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities (in shares)	7	0	0

Segment Reporting (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended								12 Months Ended
Segment Reporting (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement
Operating revenues		$ 1,992	$ 2,960	$ 2,461	$ 2,065	$ 2,154	$ 2,618	$ 2,281	$ 2,021	$ 9,478	$ 9,074	$ 8,915
Operating expenses										7,997	7,766	7,708
Depreciation and amortization										421	596	756
Impairment losses										99	1,534	483
Development costs										11	22	48
Total operating costs and expenses										8,528	9,918	8,995
Other income - affiliate	$ 84									0	87	193
Gain on sale of assets										32	16	(80)
Gain on postretirement benefits curtailment												(80)
Operating income/(loss)		49	398	174	361	(1,200)	275	214	(30)	982	(741)	33
Equity in earnings/(losses) of unconsolidated affiliates										9	(14)	(18)
Impairment losses on investments										(15)	(79)	(268)
Other income/(expenses), net										18	51	47
Loss on debt extinguishment										(44)	(49)	(142)
Interest expense										(483)	(557)	(583)
Income/(Loss) from Continuing Operations Before Income Taxes										467	(1,389)	(931)
Income tax expense/(benefit)										7	(44)	25
Net Income/(Loss) from Continuing Operations		(93)	288	27	238	(1,390)	163	60	(178)	460	(1,345)	(956)
(Loss)/income from discontinued operations, net of income tax		80	(336)	69	(5)	(265)	0	(702)	(25)	(192)	(992)	65
Net Income/(Loss)		(13)	(48)	96	233	(1,655)	163	(642)	(203)	268	(2,337)	(891)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests		(2)	$ 24	$ 24	$ (46)	(120)	$ (8)	$ (16)	$ (40)	0	(184)	(117)
Net Income/(Loss) Attributable to NRG Energy, Inc.										268	(2,153)	(774)
Balance sheet
Equity investments in affiliates	182	412				182				412	182
Capital expenditures	250	388				250				388	250
Goodwill	539	573				539				573	539
Total assets	23,355	10,628				23,355				10,628	23,355
Eliminations
Income Statement
Operating revenues										(1,068)	(923)	(1,122)
Operating expenses										(1,066)	(925)	(1,129)
Depreciation and amortization										0	(3)	(3)
Impairment losses										0	0	0
Development costs										(1)	0	0
Total operating costs and expenses										(1,067)	(928)	(1,132)
Other income - affiliate											0	0
Gain on sale of assets										0	0
Gain on postretirement benefits curtailment												0
Operating income/(loss)										(1)	5	10
Equity in earnings/(losses) of unconsolidated affiliates										(5)	(5)	0
Impairment losses on investments										0	0	0
Other income/(expenses), net										(1)	0	(2)
Loss on debt extinguishment										0	0	0
Interest expense										0	0	2
Income/(Loss) from Continuing Operations Before Income Taxes										(7)	0	10
Income tax expense/(benefit)										0	0	0
Net Income/(Loss) from Continuing Operations										(7)	0	10
(Loss)/income from discontinued operations, net of income tax										0	0	0
Net Income/(Loss)										(7)	0	10
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests										(5)	0	(12)
Net Income/(Loss) Attributable to NRG Energy, Inc.										(2)	0	22
Balance sheet
Equity investments in affiliates	(92)	0				(92)				0	(92)
Capital expenditures	0	0				0				0	0
Goodwill	0	0				0				0	0
Total assets	(5,792)	(5,401)				(5,792)				(5,401)	(5,792)
Retail \| Operating Segments
Income Statement
Operating revenues										7,103	6,369	6,330
Operating expenses										5,919	5,377	5,162
Depreciation and amortization										116	110	114
Impairment losses										1	8	1
Development costs										1	3	4
Total operating costs and expenses										6,037	5,498	5,281
Other income - affiliate											0	0
Gain on sale of assets										0	0
Gain on postretirement benefits curtailment												(1)
Operating income/(loss)										1,066	871	1,048
Equity in earnings/(losses) of unconsolidated affiliates										0	0	0
Impairment losses on investments										0	0	0
Other income/(expenses), net										0	0	(6)
Loss on debt extinguishment										0	0	0
Interest expense										(3)	(6)	6
Income/(Loss) from Continuing Operations Before Income Taxes										1,063	865	1,048
Income tax expense/(benefit)										1	(8)	1
Net Income/(Loss) from Continuing Operations										1,062	873	1,047
(Loss)/income from discontinued operations, net of income tax										0	0	0
Net Income/(Loss)										1,062	873	1,047
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests										1	1	0
Net Income/(Loss) Attributable to NRG Energy, Inc.										1,061	872	1,047
Balance sheet
Equity investments in affiliates	0	0				0				0	0
Capital expenditures	82	90				82				90	82
Goodwill	374	408				374				408	374
Total assets	2,655	3,291				2,655				3,291	2,655
Retail \| Eliminations
Income Statement
Operating revenues										(9)	(4)	(16)
Generation \| Operating Segments
Income Statement
Operating revenues										3,432	3,615	3,633
Operating expenses										3,019	3,071	3,322
Depreciation and amortization										272	454	593
Impairment losses										98	1,526	452
Development costs										9	13	15
Total operating costs and expenses										3,398	5,064	4,382
Other income - affiliate											0	0
Gain on sale of assets										2	15
Gain on postretirement benefits curtailment												0
Operating income/(loss)										36	(1,434)	(749)
Equity in earnings/(losses) of unconsolidated affiliates										10	(14)	(63)
Impairment losses on investments										(15)	(75)	(248)
Other income/(expenses), net										20	23	22
Loss on debt extinguishment										0	0	0
Interest expense										(58)	(100)	(96)
Income/(Loss) from Continuing Operations Before Income Taxes										(7)	(1,600)	(1,134)
Income tax expense/(benefit)										0	2	(1)
Net Income/(Loss) from Continuing Operations										(7)	(1,602)	(1,133)
(Loss)/income from discontinued operations, net of income tax										0	0	0
Net Income/(Loss)										(7)	(1,602)	(1,133)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests										9	4	(1)
Net Income/(Loss) Attributable to NRG Energy, Inc.										(16)	(1,606)	(1,132)
Balance sheet
Equity investments in affiliates	179	412				179				412	179
Capital expenditures	148	267				148				267	148
Goodwill	165	165				165				165	165
Total assets	9,090	5,735				9,090				5,735	9,090
Generation \| Eliminations
Income Statement
Operating revenues										(1,085)	(877)	(999)
Corporate \| Operating Segments
Income Statement
Operating revenues										11	13	74
Operating expenses										125	243	353
Depreciation and amortization										33	35	52
Impairment losses										0	0	30
Development costs										2	6	29
Total operating costs and expenses										160	284	464
Other income - affiliate											87	193
Gain on sale of assets										30	1
Gain on postretirement benefits curtailment												(79)
Operating income/(loss)										(119)	(183)	(276)
Equity in earnings/(losses) of unconsolidated affiliates										4	5	45
Impairment losses on investments										0	(4)	(20)
Other income/(expenses), net										(1)	28	33
Loss on debt extinguishment										(44)	(49)	(142)
Interest expense										(422)	(451)	(495)
Income/(Loss) from Continuing Operations Before Income Taxes										(582)	(654)	(855)
Income tax expense/(benefit)										6	(38)	25
Net Income/(Loss) from Continuing Operations										(588)	(616)	(880)
(Loss)/income from discontinued operations, net of income tax										(192)	(992)	65
Net Income/(Loss)										(780)	(1,608)	(815)
Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests										(5)	(189)	(104)
Net Income/(Loss) Attributable to NRG Energy, Inc.										(775)	(1,419)	(711)
Balance sheet
Equity investments in affiliates	95	0				95				0	95
Capital expenditures	20	31				20				31	20
Goodwill	0	0				0				0	0
Total assets	$ 17,402	$ 7,003				$ 17,402				7,003	17,402
Corporate \| Eliminations
Income Statement
Operating revenues										$ 26	$ (42)	$ (107)
Customer Concentration Risk
Segment Reporting Information
Concentration Risk, Percentage											0.00%	0.00%
Customer Concentration Risk \| Generation
Segment Reporting Information
Concentration Risk, Percentage										11.00%

Income Taxes - Income Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current
State	$ 6	$ 19	$ 6
Total — current	6	19	6
Deferred
U.S. Federal	(16)	(60)	23
State	16	(5)	(6)
Foreign	1	2	2
Total — deferred	1	(63)	19
Income tax expense/(benefit)	7	(44)	25
Domestic and foreign components of income from continuing operations before income tax expense
U.S.	468	(1,406)	(942)
Foreign	(1)	17	11
Income/(Loss) from Continuing Operations Before Income Taxes	467	(1,389)	(931)
Reconciliation of the U.S. federal statutory rate to NRG's effective rate from continuing operations
Income/(loss) from continuing operations before income taxes	467	(1,389)	(931)
Tax at federal statutory tax rate	98	(486)	(326)
State taxes	18	19	0
Foreign operations	0	2	10
Permanent differences	7	0	0
Tax Act - corporate income tax rate change	0	665	0
Valuation allowance due to corporate income tax rate change	0	(660)	0
Valuation allowance due to corporate income tax rate change	(106)	455	382
Impact of non-taxable equity earnings	0	(5)	22
Book goodwill impairment	0	30	0
Net interest accrued on uncertain tax positions	0	0	1
Production tax credits (PTC)	(7)	(8)	(7)
Recognition of uncertain tax benefits	1	(5)	2
State rate change including true-up to current period activity	0	0	(59)
Alternative minimum tax (AMT) refundable credit	(4)	(64)	0
Other	0	13	0
Income tax expense/(benefit)	$ 7	$ (44)	$ 25
Effective income tax rate (as a percent)	1.50%	3.20%	(2.70%)

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred tax liabilities:
Emissions allowances	$ 15	$ 15
Derivatives, net	37	17
Investment in projects	180	337
Discount/premium on notes	0	1
Deferred financing costs	21	2
Other	1	5
Discontinued operations	36	49
Total deferred tax liabilities	290	426
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	134	141
Difference between book and tax basis of property	554	611
Goodwill	11	38
Differences between book and tax basis of contracts	38	52
Pension and other postretirement benefits	87	74
Equity compensation	9	10
Bad debt reserve	14	14
U.S. capital loss carryforwards	0	1
U.S. Federal net operating loss carryforwards	2,241	596
Foreign net operating loss carryforwards	62	66
State net operating loss carryforwards	379	128
Foreign capital loss carryforwards	1	1
Federal and state tax credit carryforwards	381	368
Federal benefit on state uncertain tax positions	6	7
Intangibles amortization (excluding goodwill)	21	98
Interest disallowance carryforward per §163(j) of the Tax Act	102	0
Inventory obsolescence	7	12
Discontinued operations	17	185
Total deferred tax assets	4,064	2,402
Valuation allowance	(3,812)	(1,855)
Discontinued operations	19	(8)
Total deferred tax assets, net of valuation allowance	271	539
NRG's net deferred tax position
Net deferred tax liability	(19)
Net deferred tax asset		113
Continuing Operations
NRG's net deferred tax position
Deferred tax asset	46	6
Deferred tax liability— continuing operations	65	21
Discontinued Operations
NRG's net deferred tax position
Deferred tax asset	$ 0	$ 128

Income Taxes - Deferred Tax Assets and Valuation Allowance, Taxes Receivable and Payable (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Taxes receivable and payable
Net deferred tax asset	$ 3,800	$ 2,000
Valuation allowance	3,812	1,855
Deferred tax liability	19
Net deferred tax asset		113
Foreign net operating loss carryforwards	62	66
Foreign capital loss carryforwards	1	$ 1
Current taxes payable	3
Current taxes receivable	1
Federal Tax Authority
Taxes receivable and payable
Valuation allowance	3,300
Operating loss carryforwards	2,200
State and Local Jurisdiction
Taxes receivable and payable
Valuation allowance	454
Operating loss carryforwards	379
Foreign Tax Authority
Taxes receivable and payable
Deferred tax liability	16
Operating loss carryforwards	$ 62

Income Taxes - Reconciliation of Uncertain Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Uncertain tax benefits
Uncertain tax benefits	$ 30	$ 34	$ 26	$ 30
Liability for uncertainty in income taxes, noncurrent			30	33
Unrecognized tax benefits, income tax penalties expense	1
Accrued interest and penalties related to unrecognized tax benefits			$ 4	$ 3
Uncertain tax benefits reconciliation
Balance as of January 1	30	34
Increase due to current year positions	4	4
Decrease due to prior year positions	0	(8)
Decrease due to settlements and payments	(8)	0
Uncertain tax benefits as of December 31	$ 26	$ 30

Stock-Based Compensation - Long-Term Incentive Plan (Details) - shares	Apr. 27, 2017	Dec. 31, 2018	Dec. 31, 2017
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
Number of shares available for grant under plan		8,564,611	8,724,595
NRG GenOn LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance under plan		0
Number of shares available for grant under plan		520,182	1,369,880

Stock-Based Compensation - Non-Qualified Stock Options (Details) - NQSOs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock-Based Compensation
Maximum contractual term for outstanding options (in years)	10 years
Shares granted during the period	0	0	0
NQSO activity and changes
Outstanding at the beginning of the period (in shares)	1,285,858
Forfeited (in shares)	(36,866)
Exercised (in shares)	(969,058)		0
Outstanding at the end of the period (in shares)	279,934.000000	1,285,858
Exercisable at the end of the period (in shares)	279,934
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding (in usd per share)	$ 25.49
Forfeited (in usd per share)	43.64
Exercised (in usd per share)	24.93
Outstanding (in usd per share)	25.04	$ 25.49
Exercisable (in usd per share)	$ 25.04
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures
Weighted Average Remaining Contractual Term, Outstanding	2 years	3 years
Weighted Average Remaining Contractual Term, Exercisable	2 years
Aggregate Intrinsic Value, beginning of period	$ 6
Aggregate Intrinsic Value, end of period	4	$ 6
Aggregate Intrinsic Value, Exercisable	$ 4
GenOn Employees
NQSO activity and changes
Outstanding at the end of the period (in shares)	26,430
Exercisable at the end of the period (in shares)	26,430,000,000

Stock-Based Compensation - Intrinsic Value of Options Exercised and Cash Received (Details) - NQSOs - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total intrinsic value of options exercised	$ 10	$ 1	$ 0
Cash received from options exercised	$ 24	$ 4	$ 0
Options exercised (in shares)	969,058		0

Stock-Based Compensation - Restricted Stock Units (RSUs (Details) - RSUs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock-Based Compensation
Award vesting period	3 years
Units
Non-vested at beginning of period (in shares)	2,377,813
Granted (in shares)	447,309
Forfeited (in shares)	(315,569)
Vested (in shares)	(1,051,471)
Non-vested at end of period (in shares)	1,458,082.000000	2,377,813
Weighted Average Grant Date Fair Value per Unit
Non-vested at beginning of period (in usd per share)	$ 14.63
Granted (in usd per share)	28.90	$ 12.44	$ 11.54
Forfeited (in usd per share)	18.93
Vested (in usd per share)	17.67
Non-vested at end of period (in usd per share)	$ 16.16	$ 14.63
Vested in period, fair value	$ 42	$ 19	$ 11
GenOn Employees
Units
Non-vested at end of period (in shares)	7,319

Stock-Based Compensation - Deferred Stock Units, DSUs (Details) - DSUs - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Units
Balance outstanding at the beginning of the period (in shares)	427,148
Granted (in shares)	61,645
Converted to Common Stock (in shares)	(156,878)
Balance outstanding at the end of the period (in shares)	331,915.000000	427,148
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)	33.43	$ 16.76	$ 16.85
Vested (in usd per share)	23.59
Balance outstanding at the end of the period (in usd per share)	$ 22.94	$ 21.54
Aggregate intrinsic value for DSUs outstanding	$ 13,000,000	$ 12,000,000	$ 6,000,000
Aggregate intrinsic values for DSUs converted to common stock during the period	$ 0	$ 4,000,000	$ 1,000,000
GenOn Employees
Units
Granted (in shares)	0

Stock-Based Compensation - Performance Stock Units, RPSUs and MSUs (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Performance Stock Units
Units
Non-vested at beginning of period (in shares)	1,858,821
Granted (in shares)	372,147
Forfeited (in shares)	(134,473)
Vested (in shares)	(385,861)
Non-vested at end of period (in shares)	1,710,634.000000	1,858,821
Weighted Average Grant-Date Fair Value per Unit
Non-vested at beginning of period (in usd per share)	$ 18.27
Granted (in usd per share)	35.36
Forfeited (in usd per share)	22.26
Vested (in usd per share)	30.31
Non-vested at end of period (in usd per share)	$ 19.12	$ 18.27
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	47.52%	43.96%
Expected term (in years)	3 years	3 years
Risk free rate	2.01%	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)		$ 15.91	$ 14.73
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, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock-Based Compensation
Minimum tax withholdings		$ 19.0	$ 5.0	$ 5.0
Compensation Expense		41.0	38.0	20.0
Tax detriment recognized		(4.0)	(5.0)	(4.0)
Unrecognized Total Cost		33.0
GenOn
Stock-Based Compensation
Compensation Expense	$ 1.0	1.0	6.0	4.0
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
RSUs
Stock-Based Compensation
Compensation Expense		$ 12.0	15.0	12.0
Unrecognized Total Cost		$ 9.0
Weighted Average Recognition Period Remaining (In years)		10 months 21 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		$ 4.0	5.0	2.0
Unrecognized Total Cost		$ 0.0
Weighted Average Recognition Period Remaining (In years)		11 days
RPSUs
Stock-Based Compensation
Compensation Expense		$ 7.0	3.0	0.0
Unrecognized Total Cost		$ 10.0
Weighted Average Recognition Period Remaining (In years)		1 year 3 months 26 days
PRSUs
Stock-Based Compensation
Compensation Expense		$ 16.0	$ 13.0	$ 4.0
Unrecognized Total Cost		$ 14.0
Weighted Average Recognition Period Remaining (In years)		1 year 2 months 1 day
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, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	$ 32	$ 8	$ 7
Gladstone
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	3	3	2
GenConn
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	4	5	5
Ivanpah
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	20	0	0
Midway-Sunset
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	$ 5	$ 0	$ 0

Related Party Transactions - Service Agreement and Transition Service Agreement with GeOn (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Jul. 16, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jun. 12, 2017
Related Party Transaction [Line Items]
Service fees			$ 32	$ 8	$ 7
Other income - affiliate		$ 84	0	87	$ 193
Services Agreement \| GenOn
Related Party Transaction [Line Items]
Credit applied		$ 28
Services Agreement \| Restructuring Support Agreement
Related Party Transaction [Line Items]
Shared services annualized rate						$ 84
Services Agreement \| Restructuring Support Agreement \| GenOn
Related Party Transaction [Line Items]
Credit applied	$ 28
Transition Services Agreement \| Restructuring Support Agreement \| GenOn
Related Party Transaction [Line Items]
Other income - affiliate				87
Shared service, selling, general and administrative			53	$ 42
Management Service \| Services Agreement \| GenOn
Related Party Transaction [Line Items]
Service fees			$ 193

Related Party Transactions - Credit Agreement with GenOn and Commercial Operations Agreement (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Long-term debt	$ 6,691,000,000	$ 9,494,000,000
Cash collateral posted in support of energy risk management activities	287,000,000	171,000,000
GenOn
Related Party Transaction [Line Items]
Cash collateral posted in support of energy risk management activities	4,000,000	32,000,000
Revolving Credit Facility \| Intercompany Credit Agreement \| GenOn
Related Party Transaction [Line Items]
Revolving credit facility	500,000,000
Letters of credit outstanding under revolver	$ 30,000,000	$ 92,000,000

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Coal, Gas and Transportation Commitments

Out-of-market contracts, net

$ 121

$ 129

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

222

239

Other Leased Property

Coal, Gas and Transportation Commitments

Lease expense

$ 69

$ 85

Future commitments under coal, gas and transportation contractual agreements

^[1]

$ 332

EME Project Financings

Coal, Gas and Transportation Commitments

Leased Interest

100.00%

Out-of-market contracts, net

$ 159

Lease expense

$ 14

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjEyZTkyODliYzNiMTQ3YTJiMTQzZmVjMzA2NGQyYjYzfFRleHRTZWxlY3Rpb246NjlCNEE4NzA0MUU2ODFCQjlDMzA5OEMyQjZFQzE0MEEM}

Commitments and Contingencies - Transportation and Purchased Power Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Minimum purchase commitment
2019	$ 30
2020	13
2021	12
2022	11
2023	1
Thereafter	1
Total	$ 68
Maximum remaining term under individual purchased power contract (in years)	10 years
Coal, Gas and Transportation Commitments
Commitments and Contingencies
Purchases	$ 1,200	$ 1,000	$ 1,100
Minimum purchase commitment
2019	227
2020	156
2021	122
2022	74
2023	55
Thereafter	209
Total	$ 843

Commitments and Contingencies - Narrative (Details) - USD ($) $ in Thousands				12 Months Ended
	Mar. 27, 2018	Jan. 29, 2016	Jun. 01, 2001	Dec. 31, 2018	Apr. 01, 2019	Dec. 31, 2016
Loss Contingencies [Line Items]
Nuclear insurance liability limit per incident				$ 14,070,000
Required nuclear liability insurance				450,000
Nuclear financial protection pool mandated by the Price-Anderson Act				13,400,000
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident				$ 138,000
Maximum assessment, administrative fee (as percent)				5.00%
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident				$ 21,000
44% maximum assessment				44.00%
Nuclear operator maximum annual assessment				$ 9,000
Maximum liability per nuclear incident				61,000
Mutual property insurance additional blanket policy property coverage				1,250,000
Nuclear property insurance coverage limit per individual insured				1,500,000
Lost revenue insurance maximum weekly recovery				3,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss				$ 1,980
Multiplier that the industry mutual insurance company may assess against insureds premium				10
The number of months a nuclear industry mutual insurance company will respond to retrospective premium adjustments				24 months
Number of years board of directors of industry mutual insurance company can adjust policy after policy expires				6 years
Midwest Generation Asbestos Liabilities
Loss Contingencies [Line Items]
Damages sought	$ 61,000
CDWR and SDGE v Sunrise Power
Loss Contingencies [Line Items]
Power Purchase Agreement (PPA) period			10 years
Damages sought		$ 1,200
Remaining term		70 months
Nuclear Event
Loss Contingencies [Line Items]
Total nuclear property insurance coverage				$ 2,750,000
Lost revenue insurance maximum weekly recovery				274,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss				216,000
Non-nuclear Event
Loss Contingencies [Line Items]
Total nuclear property insurance coverage				1,500,000
Lost revenue insurance maximum weekly recovery				184,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss				$ 144,000
Non-nuclear Event \| Scenario, Forecast
Loss Contingencies [Line Items]
Total nuclear property insurance coverage					$ 1,000,000
Lignite Contract with Texas Westmoreland Coal Co.
Loss Contingencies [Line Items]
Bond obligation						$ 99,000

Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
Cash Flow Information (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Interest paid, net of amount capitalized	$ 436	$ 543	$ 606
Income taxes paid	9	9	14
Additions to fixed assets for accrued capital expenditures	$ 20	$ 19	$ 9

Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
Guarantees (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Guarantor Obligations
Under 1 Year	$ 1,138
1-3 Years	188
3-5 Years	257
Over 5 Years	1,184
Guarantees by Remaining Maturity, Total	2,767	$ 1,960
Letters of credit and surety bonds
Guarantor Obligations
Under 1 Year	1,138
1-3 Years	79
3-5 Years	0
Over 5 Years	36
Guarantees by Remaining Maturity, Total	$ 1,253	1,003
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	4
3-5 Years	257
Over 5 Years	532
Guarantees by Remaining Maturity, Total	793	312
Other guarantees
Guarantor Obligations
Under 1 Year	0
1-3 Years	105
3-5 Years	0
Over 5 Years	616
Guarantees by Remaining Maturity, Total	721	645
Eliminations \| Letters of credit and surety bonds
Guarantor Obligations
Guarantees by Remaining Maturity, Total		$ 92
GenOn \| Letters of credit and surety bonds
Guarantor Obligations
Guarantees by Remaining Maturity, Total	$ 32

Jointly Owned Plants (Details) $ in Millions	Dec. 31, 2018 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	$ 382
Accumulated Depreciation	(185)
Construction in Progress	$ 5
Cedar Bayou Unit 4, Baytown, TX
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	50.00%
Property, Plant & Equipment	$ 215
Accumulated Depreciation	(84)
Construction in Progress	$ 8

Unaudited Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 1,992	$ 2,960	$ 2,461	$ 2,065	$ 2,154	$ 2,618	$ 2,281	$ 2,021	$ 9,478	$ 9,074	$ 8,915
Operating income	49	398	174	361	(1,200)	275	214	(30)	982	(741)	33
Net (loss)/income from continuing operations	(93)	288	27	238	(1,390)	163	60	(178)	460	(1,345)	(956)
(Loss)/income from discontinued operations, net of income tax	80	(336)	69	(5)	(265)	0	(702)	(25)	(192)	(992)	65
Net Income/(Loss)	(13)	(48)	96	233	(1,655)	163	(642)	(203)	268	(2,337)	(891)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(2)	24	24	(46)	(120)	(8)	(16)	(40)	0	(184)	(117)
Net (loss)/income attributable to NRG Energy, Inc.									268	(2,153)	(774)
(Loss)/income available to Common Stockholders	$ (11)	$ (72)	$ 72	$ 279	$ (1,535)	$ 171	$ (626)	$ (163)	$ 268	$ (2,153)	$ (701)
Weighted average number of common shares outstanding — basic (in shares)	289,000,000	299,000,000	310,000,000	318,000,000	317,000,000	317,000,000	316,000,000	316,000,000	304,000,000	317,000,000	316,000,000
Income/(loss) from discontinued operations per weighted average common share — basic (in usd per share)	$ 0.28	$ (1.12)	$ 0.22	$ (0.02)	$ (0.84)	$ 0.00	$ (2.22)	$ (0.08)	$ (0.63)	$ (3.13)	$ 0.20
Income/(Loss) per weighted average common share — basic (in usd per share)	$ (0.04)	$ (0.24)	$ 0.23	$ 0.88	$ (4.84)	$ 0.54	$ (1.98)	$ (0.52)	$ 0.88	$ (6.79)	$ (2.22)
Weighted average number of common shares outstanding — diluted (in shares)	289,000,000	299,000,000	314,000,000	322,000,000	317,000,000	322,000,000	316,000,000	316,000,000	308,000,000	317,000,000	316,000,000
Income/(loss) from discontinued operations per weighted average common share — diluted (in usd per share)	$ 0.28	$ (1.12)	$ 0.22	$ (0.02)	$ (0.84)	$ 0.00	$ (2.22)	$ (0.08)	$ (0.62)	$ (3.13)	$ 0.20
Net (loss)/income per weighted average common share — diluted (in usd per share)	$ (0.04)	$ (0.24)	$ 0.23	$ 0.87	$ (4.84)	$ 0.53	$ (1.98)	$ (0.52)	$ 0.87	$ (6.79)	$ (2.22)

Condensed Consolidating Financial Information (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument
Long-term debt	$ 6,691	$ 9,494
Recourse Debt
Debt Instrument
Long-term debt	6,523	$ 7,182
Senior Notes \| Recourse Debt
Debt Instrument
Long-term debt	$ 4,400

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues
Total operating revenues		$ 1,992	$ 2,960	$ 2,461	$ 2,065	$ 2,154	$ 2,618	$ 2,281	$ 2,021	$ 9,478	$ 9,074	$ 8,915
Operating Costs and Expenses
Cost of operations										7,108	6,886	6,676
Depreciation and amortization										421	596	756
Impairment losses										99	1,534	483
Selling, general and administrative										799	836	1,032
Reorganization costs										90	44
Development costs										11	22	48
Total operating costs and expenses										8,528	9,918	8,995
Other income - affiliate	$ 84									0	87	193
Gain on sale of assets										32	16	(80)
Operating Income/(Loss)		49	398	174	361	(1,200)	275	214	(30)	982	(741)	33
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries										0	0	0
Equity in earnings/(losses) of unconsolidated affiliates										9	(14)	(18)
Impairment losses on investments										(15)	(79)	(268)
Other income, net										18	51	47
Loss on debt extinguishment, net										(44)	(49)	(142)
Interest expense										(483)	(557)	(583)
Total other expense										(515)	(648)	(964)
Income/(Loss) from Continuing Operations Before Income Taxes										467	(1,389)	(931)
Income tax (benefit)/expense										7	(44)	25
Net Income/(Loss) from Continuing Operations		(93)	288	27	238	(1,390)	163	60	(178)	460	(1,345)	(956)
(Loss)/income from discontinued operations, net of income tax		80	(336)	69	(5)	(265)	0	(702)	(25)	(192)	(992)	65
Net Income/(Loss)		(13)	(48)	96	233	(1,655)	163	(642)	(203)	268	(2,337)	(891)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests		$ (2)	$ 24	$ 24	$ (46)	$ (120)	$ (8)	$ (16)	$ (40)	0	(184)	(117)
Net Income/(Loss) Attributable to NRG Energy, Inc.										268	(2,153)	(774)
Eliminations
Operating Revenues
Total operating revenues										(26)	(48)	(74)
Operating Costs and Expenses
Cost of operations										(26)	(46)	(80)
Depreciation and amortization										0	0	0
Impairment losses										0	0	0
Selling, general and administrative										(74)	(2)	0
Reorganization costs										0	0
Development costs										(1)	0	0
Total operating costs and expenses										(101)	(48)	(80)
Other income - affiliate											0	0
Gain on sale of assets										0	0	0
Operating Income/(Loss)										75	0	6
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries										(1,314)	(46)	(324)
Equity in earnings/(losses) of unconsolidated affiliates										0	0	(10)
Impairment losses on investments										0	0	0
Other income, net										0	0	0
Loss on debt extinguishment, net										0	0	0
Interest expense										0	0	0
Total other expense										(1,314)	(46)	(334)
Income/(Loss) from Continuing Operations Before Income Taxes										(1,239)	(46)	(328)
Income tax (benefit)/expense										0	0	0
Net Income/(Loss) from Continuing Operations										(1,239)	(46)	(328)
(Loss)/income from discontinued operations, net of income tax										0	0	0
Net Income/(Loss)										(1,239)	(46)	(328)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests										75	0	(4)
Net Income/(Loss) Attributable to NRG Energy, Inc.										(1,314)	(46)	(324)
Guarantor Subsidiaries
Operating Revenues
Total operating revenues										8,119	7,818	7,539
Operating Costs and Expenses
Cost of operations										6,147	5,998	5,581
Depreciation and amortization										238	343	500
Impairment losses										6	1,346	370
Selling, general and administrative										462	410	430
Reorganization costs										4	6
Development costs										0	0	0
Total operating costs and expenses										6,857	8,103	6,881
Other income - affiliate											0	0
Gain on sale of assets										4	4	(1)
Operating Income/(Loss)										1,266	(281)	657
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries										23	18	(50)
Equity in earnings/(losses) of unconsolidated affiliates										0	0	5
Impairment losses on investments										0	0	0
Other income, net										32	9	5
Loss on debt extinguishment, net										0	0	0
Interest expense										(14)	(14)	(15)
Total other expense										41	13	(55)
Income/(Loss) from Continuing Operations Before Income Taxes										1,307	(268)	602
Income tax (benefit)/expense										372	(598)	(1)
Net Income/(Loss) from Continuing Operations										935	330	603
(Loss)/income from discontinued operations, net of income tax										62	91	86
Net Income/(Loss)										997	421	689
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests										0	0	0
Net Income/(Loss) Attributable to NRG Energy, Inc.										997	421	689
Non-Guarantor Subsidiaries
Operating Revenues
Total operating revenues										1,385	1,304	1,450
Operating Costs and Expenses
Cost of operations										959	862	1,116
Depreciation and amortization										150	221	230
Impairment losses										93	188	113
Selling, general and administrative										63	64	144
Reorganization costs										0	0
Development costs										1	4	18
Total operating costs and expenses										1,266	1,339	1,621
Other income - affiliate											0	0
Gain on sale of assets										28	12	0
Operating Income/(Loss)										147	(23)	(171)
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries										0	0	0
Equity in earnings/(losses) of unconsolidated affiliates										10	(10)	(9)
Impairment losses on investments										(15)	(75)	(252)
Other income, net										(13)	14	15
Loss on debt extinguishment, net										0	0	(4)
Interest expense										(49)	(91)	(85)
Total other expense										(67)	(162)	(335)
Income/(Loss) from Continuing Operations Before Income Taxes										80	(185)	(506)
Income tax (benefit)/expense										19	(62)	28
Net Income/(Loss) from Continuing Operations										61	(123)	(534)
(Loss)/income from discontinued operations, net of income tax										75	(420)	0
Net Income/(Loss)										136	(543)	(534)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests										(181)	(168)	(169)
Net Income/(Loss) Attributable to NRG Energy, Inc.										317	(375)	(365)
NRG Energy, Inc. (Note Issuer)
Operating Revenues
Total operating revenues										0	0	0
Operating Costs and Expenses
Cost of operations										28	72	59
Depreciation and amortization										33	32	26
Impairment losses										0	0	0
Selling, general and administrative										348	364	458
Reorganization costs										86	38
Development costs										11	18	30
Total operating costs and expenses										506	524	573
Other income - affiliate											87	193
Gain on sale of assets										0	0	(79)
Operating Income/(Loss)										(506)	(437)	(459)
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries										1,291	28	374
Equity in earnings/(losses) of unconsolidated affiliates										(1)	(4)	(4)
Impairment losses on investments										0	(4)	(16)
Other income, net										(1)	28	27
Loss on debt extinguishment, net										(44)	(49)	(138)
Interest expense										(420)	(452)	(483)
Total other expense										825	(453)	(240)
Income/(Loss) from Continuing Operations Before Income Taxes										319	(890)	(699)
Income tax (benefit)/expense										(384)	616	(2)
Net Income/(Loss) from Continuing Operations										703	(1,506)	(697)
(Loss)/income from discontinued operations, net of income tax										(329)	(663)	(21)
Net Income/(Loss)										374	(2,169)	(718)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests										106	(16)	56
Net Income/(Loss) Attributable to NRG Energy, Inc.										$ 268	$ (2,153)	$ (774)

Condensed Consolidating Financial Information - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net (Loss)/Income	$ (13)	$ (48)	$ 96	$ 233	$ (1,655)	$ 163	$ (642)	$ (203)	$ 268	$ (2,337)	$ (891)
Unrealized gain on derivatives, net									23	13	35
Foreign currency translation adjustments, net									(11)	12	(1)
Available-for-sale securities, net									1	(8)	1
Defined benefit plan, net									(35)	46	3
Other comprehensive (loss)/income									(22)	63	38
Comprehensive Income/(Loss)									246	(2,274)	(853)
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									14	(179)	(117)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.									232	(2,095)	(736)
Dividends for preferred shares									0	0	5
Gain on redemption of preferred shares									0	0	(78)
Comprehensive Income/(Loss) Available for Common Stockholders									232	(2,095)	(663)
Eliminations
Net (Loss)/Income									(1,239)	(46)	(328)
Unrealized gain on derivatives, net									(15)	(26)	(86)
Foreign currency translation adjustments, net									22	(1)	2
Available-for-sale securities, net									0	0	0
Defined benefit plan, net									9	(12)	23
Other comprehensive (loss)/income									16	(39)	(61)
Comprehensive Income/(Loss)									(1,223)	(85)	(389)
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									76	(60)	(70)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.									(1,299)	(25)	(319)
Dividends for preferred shares											0
Gain on redemption of preferred shares											0
Comprehensive Income/(Loss) Available for Common Stockholders											(319)
Guarantor Subsidiaries
Net (Loss)/Income									997	421	689
Unrealized gain on derivatives, net									0	1	0
Foreign currency translation adjustments, net									(10)	6	(1)
Available-for-sale securities, net									0	0	0
Defined benefit plan, net									(9)	(13)	44
Other comprehensive (loss)/income									(19)	(6)	43
Comprehensive Income/(Loss)									978	415	732
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									0	0	0
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.									978	415	732
Dividends for preferred shares											0
Gain on redemption of preferred shares											0
Comprehensive Income/(Loss) Available for Common Stockholders											732
Non-Guarantor Subsidiaries
Net (Loss)/Income									136	(543)	(534)
Unrealized gain on derivatives, net									29	13	32
Foreign currency translation adjustments, net									(10)	7	(1)
Available-for-sale securities, net									0	0	0
Defined benefit plan, net									0	30	(13)
Other comprehensive (loss)/income									19	50	18
Comprehensive Income/(Loss)									155	(493)	(516)
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									(166)	(103)	(103)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.									321	(390)	(413)
Dividends for preferred shares											0
Gain on redemption of preferred shares											0
Comprehensive Income/(Loss) Available for Common Stockholders											(413)
NRG Energy, Inc. (Note Issuer)
Net (Loss)/Income									374	(2,169)	(718)
Unrealized gain on derivatives, net									9	25	89
Foreign currency translation adjustments, net									(13)	0	(1)
Available-for-sale securities, net									1	(8)	1
Defined benefit plan, net									(35)	41	(51)
Other comprehensive (loss)/income									(38)	58	38
Comprehensive Income/(Loss)									336	(2,111)	(680)
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									104	(16)	56
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.									$ 232	$ (2,095)	(736)
Dividends for preferred shares											5
Gain on redemption of preferred shares											(78)
Comprehensive Income/(Loss) Available for Common Stockholders											$ (663)

Condensed Consolidating Financial Information - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 563	$ 770	$ 591
Funds deposited by counterparties	33	37	2
Restricted cash	17	279	267
Accounts receivable - trade	1,019	900
Inventory	412	453
Derivative instruments	764	624
Cash collateral posted in support of energy risk management activities	287	171
Accounts receivable - affiliate	5	180
Prepayments and other current assets	302	163
Current assets - held-for-sale	1	116
Current assets - discontinued operations	197	744
Total current assets	3,600	4,437
Property, plant and equipment, net	3,048	5,974
Other Assets
Investment in subsidiaries	0	0
Equity investments in affiliates	412	182
Goodwill	573	539
Intangible assets, net	591	507
Nuclear decommissioning trust fund	663	692
Derivative instruments	317	159
Deferred income taxes	46	6
Other non-current assets	289	310
Non-current assets - held-for-sale	77	43
Non-current assets - discontinued operations	1,012	10,506
Total other assets	3,980	12,944
Total Assets	10,628	23,355
Current Liabilities
Current portion of long-term debt and capital leases	72	204
Accounts payable	862	684
Accounts payable - affiliate	1	57
Derivative instruments	673	537
Cash collateral received in support of energy risk management activities	33	37
Accrued expenses and other current liabilities	680	756
Accrued expenses and other current liabilities - affiliate	0	161
Current liabilities - held for sale	5	72
Current liabilities - discontinued operations	72	846
Total current liabilities	2,398	3,354
Other Liabilities
Long-term debt and capital leases	6,449	9,180
Nuclear decommissioning reserve	282	269
Nuclear decommissioning trust liability	371	415
Postretirement and other benefit obligations	435	458
Derivative instruments	304	143
Deferred income taxes	65	21
Out-of-market contracts, net	121	129
Other non-current liabilities	718	534
Non-current liabilities - held-for-sale	65	8
Non-current liabilities - discontinued operations	635	6,798
Total non-current liabilities	9,445	17,955
Total Liabilities	11,843	21,309
Redeemable noncontrolling interest in subsidiaries	19	78	46	$ 29
Total Stockholders' Equity	(1,234)	1,968	$ 4,446	$ 5,434
Total Liabilities and Stockholders' Equity	10,628	23,355
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	(81)	(57)
Cash collateral posted in support of energy risk management activities	0	0
Accounts receivable - affiliate	(754)	(534)
Prepayments and other current assets	0	0
Current assets - held-for-sale	0	0
Current assets - discontinued operations	0	0
Total current assets	(835)	(591)
Property, plant and equipment, net	0	(4)
Other Assets
Investment in subsidiaries	(5,153)	(8,500)
Equity investments in affiliates	0	0
Goodwill	0	0
Intangible assets, net	0	(3)
Nuclear decommissioning trust fund	0	0
Derivative instruments	(5)	0
Deferred income taxes	0	0
Other non-current assets	(12)	0
Non-current assets - held-for-sale	0	0
Non-current assets - discontinued operations	0	(22)
Total other assets	(5,170)	(8,525)
Total Assets	(6,005)	(9,120)
Current Liabilities
Current portion of long-term debt and capital leases	0	0
Accounts payable	0	0
Accounts payable - affiliate	(754)	(534)
Derivative instruments	(81)	(57)
Cash collateral received in support of energy risk management activities	0	0
Accrued expenses and other current liabilities	0	0
Accrued expenses and other current liabilities - affiliate		0
Current liabilities - held for sale	0	0
Current liabilities - discontinued operations	0	0
Total current liabilities	(835)	(591)
Other Liabilities
Long-term debt and capital leases	(12)	0
Nuclear decommissioning reserve	0	0
Nuclear decommissioning trust liability	0	0
Postretirement and other benefit obligations	0	0
Derivative instruments	(5)	0
Deferred income taxes	0	0
Out-of-market contracts, net	0	0
Other non-current liabilities	0	0
Non-current liabilities - held-for-sale	0	0
Non-current liabilities - discontinued operations	0	0
Total non-current liabilities	(17)	0
Total Liabilities	(852)	(591)
Redeemable noncontrolling interest in subsidiaries	0	0
Total Stockholders' Equity	(5,153)	(8,529)
Total Liabilities and Stockholders' Equity	(6,005)	(9,120)
Guarantor Subsidiaries
Current Assets
Cash and cash equivalents	55	0
Funds deposited by counterparties	33	37
Restricted cash	7	4
Accounts receivable - trade	894	852
Inventory	278	307
Derivative instruments	779	647
Cash collateral posted in support of energy risk management activities	275	170
Accounts receivable - affiliate	460	685
Prepayments and other current assets	180	106
Current assets - held-for-sale	0	8
Current assets - discontinued operations	177	89
Total current assets	3,138	2,905
Property, plant and equipment, net	1,938	2,052
Other Assets
Investment in subsidiaries	446	266
Equity investments in affiliates	0	0
Goodwill	359	359
Intangible assets, net	422	455
Nuclear decommissioning trust fund	663	692
Derivative instruments	296	126
Deferred income taxes	6	377
Other non-current assets	133	64
Non-current assets - held-for-sale	0	0
Non-current assets - discontinued operations	405	456
Total other assets	2,730	2,795
Total Assets	7,806	7,752
Current Liabilities
Current portion of long-term debt and capital leases	0	0
Accounts payable	693	582
Accounts payable - affiliate	675	725
Derivative instruments	713	556
Cash collateral received in support of energy risk management activities	33	37
Accrued expenses and other current liabilities	291	313
Accrued expenses and other current liabilities - affiliate		0
Current liabilities - held for sale	0	0
Current liabilities - discontinued operations	24	34
Total current liabilities	2,429	2,247
Other Liabilities
Long-term debt and capital leases	244	244
Nuclear decommissioning reserve	282	269
Nuclear decommissioning trust liability	371	415
Postretirement and other benefit obligations	114	118
Derivative instruments	306	136
Deferred income taxes	112	112
Out-of-market contracts, net	0	0
Other non-current liabilities	288	284
Non-current liabilities - held-for-sale	0	0
Non-current liabilities - discontinued operations	58	73
Total non-current liabilities	1,775	1,651
Total Liabilities	4,204	3,898
Redeemable noncontrolling interest in subsidiaries	0	0
Total Stockholders' Equity	3,602	3,854
Total Liabilities and Stockholders' Equity	7,806	7,752
Non-Guarantor Subsidiaries
Current Assets
Cash and cash equivalents	28	150
Funds deposited by counterparties	0	0
Restricted cash	10	275
Accounts receivable - trade	82	44
Inventory	134	146
Derivative instruments	50	24
Cash collateral posted in support of energy risk management activities	12	1
Accounts receivable - affiliate	33	183
Prepayments and other current assets	32	30
Current assets - held-for-sale	1	108
Current assets - discontinued operations	20	655
Total current assets	402	1,616
Property, plant and equipment, net	957	3,689
Other Assets
Investment in subsidiaries	0	0
Equity investments in affiliates	412	181
Goodwill	214	180
Intangible assets, net	169	55
Nuclear decommissioning trust fund	0	0
Derivative instruments	4	2
Deferred income taxes	(143)	(135)
Other non-current assets	71	126
Non-current assets - held-for-sale	77	43
Non-current assets - discontinued operations	607	10,072
Total other assets	1,411	10,524
Total Assets	2,770	15,829
Current Liabilities
Current portion of long-term debt and capital leases	55	183
Accounts payable	64	47
Accounts payable - affiliate	(249)	(310)
Derivative instruments	41	38
Cash collateral received in support of energy risk management activities	0	0
Accrued expenses and other current liabilities	36	67
Accrued expenses and other current liabilities - affiliate		0
Current liabilities - held for sale	5	72
Current liabilities - discontinued operations	48	807
Total current liabilities	0	904
Other Liabilities
Long-term debt and capital leases	192	2,197
Nuclear decommissioning reserve	0	0
Nuclear decommissioning trust liability	0	0
Postretirement and other benefit obligations	1	1
Derivative instruments	3	7
Deferred income taxes	61	64
Out-of-market contracts, net	121	129
Other non-current liabilities	198	198
Non-current liabilities - held-for-sale	65	8
Non-current liabilities - discontinued operations	577	6,725
Total non-current liabilities	1,218	9,329
Total Liabilities	1,218	10,233
Redeemable noncontrolling interest in subsidiaries	19	78
Total Stockholders' Equity	1,533	5,518
Total Liabilities and Stockholders' Equity	2,770	15,829
NRG Energy, Inc.
Current Assets
Cash and cash equivalents	480	620
Funds deposited by counterparties	0	0
Restricted cash	0	0
Accounts receivable - trade	43	4
Inventory	0	0
Derivative instruments	16	10
Cash collateral posted in support of energy risk management activities	0	0
Accounts receivable - affiliate	266	(154)
Prepayments and other current assets	90	27
Current assets - held-for-sale	0	0
Current assets - discontinued operations	0	0
Total current assets	895	507
Property, plant and equipment, net	153	237
Other Assets
Investment in subsidiaries	4,707	8,234
Equity investments in affiliates	0	1
Goodwill	0	0
Intangible assets, net	0	0
Nuclear decommissioning trust fund	0	0
Derivative instruments	22	31
Deferred income taxes	183	(236)
Other non-current assets	97	120
Non-current assets - held-for-sale	0	0
Non-current assets - discontinued operations	0	0
Total other assets	5,009	8,150
Total Assets	6,057	8,894
Current Liabilities
Current portion of long-term debt and capital leases	17	21
Accounts payable	105	55
Accounts payable - affiliate	329	176
Derivative instruments	0	0
Cash collateral received in support of energy risk management activities	0	0
Accrued expenses and other current liabilities	353	376
Accrued expenses and other current liabilities - affiliate		161
Current liabilities - held for sale	0	0
Current liabilities - discontinued operations	0	5
Total current liabilities	804	794
Other Liabilities
Long-term debt and capital leases	6,025	6,739
Nuclear decommissioning reserve	0	0
Nuclear decommissioning trust liability	0	0
Postretirement and other benefit obligations	320	339
Derivative instruments	0	0
Deferred income taxes	(108)	(155)
Out-of-market contracts, net	0	0
Other non-current liabilities	232	52
Non-current liabilities - held-for-sale	0	0
Non-current liabilities - discontinued operations	0	0
Total non-current liabilities	6,469	6,975
Total Liabilities	7,273	7,769
Redeemable noncontrolling interest in subsidiaries	0	0
Total Stockholders' Equity	(1,216)	1,125
Total Liabilities and Stockholders' Equity	$ 6,057	$ 8,894

Condensed Consolidating Financial Information - Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities
Net (Loss)/Income	$ (13)	$ (48)	$ 96	$ 233	$ (1,655)	$ 163	$ (642)	$ (203)	$ 268	$ (2,337)	$ (891)
(Loss)/income from discontinued operations, net of income tax	80	(336)	69	(5)	(265)	0	(702)	(25)	(192)	(992)	65
Net Income/(Loss) from Continuing Operations	(93)	$ 288	$ 27	238	(1,390)	$ 163	$ 60	(178)	460	(1,345)	(956)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates									46	102	67
Depreciation, amortization and accretion									459	596	772
Provision for bad debts									85	68	45
Amortization of nuclear fuel									48	51	49
Amortization of financing costs and debt discount/premiums									29	29	33
Adjustment for debt extinguishment									44	49	142
Amortization of intangibles and out-of-market contracts									45	54	68
Amortization of unearned equity compensation									25	35	10
Net (gain)/loss on sale of assets and equity/cost method investments									(49)	(9)	139
Impairment losses									114	1,614	751
Changes in derivative instruments									37	(170)	16
Changes in deferred income taxes and liability for uncertain tax benefits									5	13	(12)
Changes in collateral deposits in support of risk management activities									(105)	(80)	396
Changes in nuclear decommissioning trust liability									60	11	41
GenOn settlement, net of insurance proceeds									(63)	0	0
Net loss on deconsolidation of Agua Caliente and Ivanpah projects									13	0	0
Changes in other working capital									(250)	(162)	(124)
Cash provided/(used) by continuing operations									1,003	856	1,437
Cash provided by discontinued operations									374	754	471
Net Cash Provided by Operating Activities									1,377	1,610	1,908
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired									(243)	(14)	0
Capital expenditures									(388)	(254)	(544)
Proceeds from renewable energy grants									0	8	36
Net proceeds from sale/(purchases) of emission allowances									19	66	(1)
Net proceeds from sale of emission allowances										(66)	(1)
Investments in nuclear decommissioning trust fund securities									(572)	(512)	(551)
Proceeds from sales of nuclear decommissioning trust fund securities									513	501	510
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees									1,564	430	241
Deconsolidation of Agua Caliente and Ivanpah projects									(268)	0	0
Changes in investments in unconsolidated affiliates									(39)	(57)	(33)
Net (contributions to)/distributions from discontinued operations									(60)	150	(58)
Other									(6)	22	31
Cash provided/(used) by continuing operations									520	340	(369)
Cash used by discontinued operations									(725)	(979)	(388)
Net Cash Used by Investing Activities									(205)	(639)	(757)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans									0	0	0
Payments of dividends to preferred and common stockholders									(37)	(38)	(76)
Payment for preferred shares									(1,250)
Payments for preferred shares									0	0	(226)
Payments for debt extinguishment costs									(32)	(42)	(121)
Net distributions to noncontrolling interests from subsidiaries									(16)	(30)	(27)
Proceeds/(payments) from issuance of common stock									21	(2)	1
Proceeds from issuance of long-term debt									1,100	1,178	4,412
Payments of debt issuance costs									(19)	(18)	(61)
Payments for short and long-term debt									(1,734)	(1,884)	(5,146)
Receivable from affiliate										(125)
Receivable from affiliate									(26)	(125)	0
Other									(4)	(8)	(7)
Cash used by continuing operations									(1,997)	(969)	(1,251)
Cash provided/(used) by discontinued operations									471	(169)	483
Net Cash (Used)/Provided by Financing Activities									(1,526)	(1,138)	(768)
Effect of exchange rate changes on cash and cash equivalents									1	(1)	1
Change in Cash from discontinued operations									120	(394)	566
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									(473)	226	(182)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	613				1,086				613	1,086	860
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				1,086				860	1,086	860	1,042
Eliminations
Cash Flows from Operating Activities
Net (Loss)/Income									(1,239)	(46)	(328)
(Loss)/income from discontinued operations, net of income tax									0	0	0
Net Income/(Loss) from Continuing Operations									(1,239)	(46)	(328)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates									0	0	0
Depreciation, amortization and accretion									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/cost method investments									0	0	0
Impairment losses									0	0	0
Changes in derivative instruments									(14)	(2)	3
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
Changes in nuclear decommissioning trust liability									0	0	0
GenOn settlement, net of insurance proceeds									0
Net loss on deconsolidation of Agua Caliente and Ivanpah projects									0
Changes in other working capital									1,253	48	325
Cash provided/(used) by continuing operations									0	0	0
Cash provided by discontinued operations									0	0	0
Net Cash Provided by Operating Activities									0	0	0
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired									0	0	0
Capital expenditures									0	0	0
Proceeds from renewable energy grants										0	0
Net proceeds from sale/(purchases) of emission allowances									0
Net proceeds from sale of emission allowances										0	0
Investments in nuclear decommissioning trust fund securities									0	0	0
Proceeds from sales of nuclear decommissioning trust fund securities									0	0	0
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees									0	0	0
Deconsolidation of Agua Caliente and Ivanpah projects									0
Changes in investments in unconsolidated affiliates									0	0	0
Net (contributions to)/distributions from discontinued operations									0	0	0
Other									0	0	0
Cash provided/(used) by continuing operations									0	0	0
Cash used by discontinued operations									0	0	0
Net Cash Used by Investing Activities									0	0	0
Cash Flows from Financing Activities
Payments (for)/from intercompany loans									0	0	0
Payments of dividends to preferred and common stockholders									0	0	0
Payment for preferred shares									0
Payments for preferred shares											0
Payments for debt extinguishment costs									0	0	0
Net distributions to noncontrolling interests from subsidiaries									0	0	0
Proceeds/(payments) from issuance of common stock									0	0	0
Proceeds from issuance of long-term debt									0	0	0
Payments of debt issuance costs									0	0	0
Payments for short and long-term debt									0	0	0
Receivable from affiliate										0
Receivable from affiliate									0
Other									0	0	0
Cash used by continuing operations									0	0	0
Cash provided/(used) by discontinued operations									0	0	0
Net Cash (Used)/Provided by Financing Activities									0	0	0
Effect of exchange rate changes on cash and cash equivalents									0	0	0
Change in Cash from discontinued operations									0	0	0
Net (Decrease)/Increase 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)/Income									997	421	689
(Loss)/income from discontinued operations, net of income tax									62	91	86
Net Income/(Loss) from Continuing Operations									935	330	603
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates									0	0	(5)
Depreciation, amortization and accretion									266	343	508
Provision for bad debts									79	56	42
Amortization of nuclear fuel									48	51	49
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									36	42	56
Amortization of unearned equity compensation									0	0	0
Net (gain)/loss on sale of assets and equity/cost method investments									(30)	2	70
Impairment losses									5	1,346	370
Changes in derivative instruments									25	(214)	28
Changes in deferred income taxes and liability for uncertain tax benefits									372	(300)	(1)
Changes in collateral deposits in support of risk management activities									(94)	(98)	384
Changes in nuclear decommissioning trust liability									60	11	41
GenOn settlement, net of insurance proceeds									0
Net loss on deconsolidation of Agua Caliente and Ivanpah projects									0
Changes in other working capital									311	82	(139)
Cash provided/(used) by continuing operations									2,013	1,651	2,006
Cash provided by discontinued operations									89	116	174
Net Cash Provided by Operating Activities									2,102	1,767	2,180
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired									(40)	(14)	0
Capital expenditures									(192)	(180)	(172)
Proceeds from renewable energy grants										0	0
Net proceeds from sale/(purchases) of emission allowances									19
Net proceeds from sale of emission allowances										(66)	(1)
Investments in nuclear decommissioning trust fund securities									(572)		(551)
Proceeds from sales of nuclear decommissioning trust fund securities									513	501	510
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees									14	33	0
Deconsolidation of Agua Caliente and Ivanpah projects									0
Changes in investments in unconsolidated affiliates									0	0	0
Net (contributions to)/distributions from discontinued operations									0	0	0
Other									0	18	27
Cash provided/(used) by continuing operations									(258)	(88)	(187)
Cash used by discontinued operations									0	(13)	(9)
Net Cash Used by Investing Activities									(258)	(101)	(196)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans									(1,701)	(1,525)	(1,856)
Payments of dividends to preferred and common stockholders									0	0	0
Payment for preferred shares									0
Payments for preferred shares											0
Payments for debt extinguishment costs									0	0	0
Net distributions to noncontrolling interests from subsidiaries									0	0	0
Proceeds/(payments) from issuance of common stock									0	0	0
Proceeds from issuance of long-term debt									0	0	0
Payments of debt issuance costs									0	0	0
Payments for short and long-term debt									0	0	(2)
Receivable from affiliate										0
Receivable from affiliate									0
Other									0	0	(3)
Cash used by continuing operations									(1,701)	(1,525)	(1,861)
Cash provided/(used) by discontinued operations									0	(109)	(163)
Net Cash (Used)/Provided by Financing Activities									(1,701)	(1,634)	(2,024)
Effect of exchange rate changes on cash and cash equivalents									0	0	0
Change in Cash from discontinued operations									89	(6)	2
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									54	38	(42)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	95				41				95	41	3
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				41				3	41	3	45
Non-Guarantor Subsidiaries
Cash Flows from Operating Activities
Net (Loss)/Income									136	(543)	(534)
(Loss)/income from discontinued operations, net of income tax									75	(420)	0
Net Income/(Loss) from Continuing Operations									61	(123)	(534)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates									47	12	(14)
Depreciation, amortization and accretion									160	221	238
Provision for bad debts									6	0	3
Amortization of nuclear fuel									0	0	0
Amortization of financing costs and debt discount/premiums									6	13	13
Adjustment for debt extinguishment									0	0	4
Amortization of intangibles and out-of-market contracts									9	12	12
Amortization of unearned equity compensation									0	0	0
Net (gain)/loss on sale of assets and equity/cost method investments									(20)	(11)	0
Impairment losses									109	264	365
Changes in derivative instruments									15	50	21
Changes in deferred income taxes and liability for uncertain tax benefits									5	(9)	49
Changes in collateral deposits in support of risk management activities									(11)	18	12
Changes in nuclear decommissioning trust liability									0	0	0
GenOn settlement, net of insurance proceeds									0
Net loss on deconsolidation of Agua Caliente and Ivanpah projects									13
Changes in other working capital									(193)	(354)	(54)
Cash provided/(used) by continuing operations									207	93	115
Cash provided by discontinued operations									285	638	297
Net Cash Provided by Operating Activities									492	731	412
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired									(203)	0	0
Capital expenditures									(151)	(43)	(326)
Proceeds from renewable energy grants										8	36
Net proceeds from sale/(purchases) of emission allowances									0
Net proceeds from sale of emission allowances										0	0
Investments in nuclear decommissioning trust fund securities									0	0	0
Proceeds from sales of nuclear decommissioning trust fund securities									0	0	0
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees									8	54	56
Deconsolidation of Agua Caliente and Ivanpah projects									(268)
Changes in investments in unconsolidated affiliates									(39)	(57)	(33)
Net (contributions to)/distributions from discontinued operations									(60)	0	0
Other									0	4	4
Cash provided/(used) by continuing operations									(713)	(34)	(263)
Cash used by discontinued operations									(725)	(966)	(379)
Net Cash Used by Investing Activities									(1,438)	(1,000)	(642)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans									113	(39)	375
Payments of dividends to preferred and common stockholders									0	0	0
Payment for preferred shares									0
Payments for preferred shares											0
Payments for debt extinguishment costs									0	0	0
Net distributions to noncontrolling interests from subsidiaries									(16)	(30)	(27)
Proceeds/(payments) from issuance of common stock									0	0	0
Proceeds from issuance of long-term debt									163	94	271
Payments of debt issuance costs									0	(2)	0
Payments for short and long-term debt									(138)	(183)	(221)
Receivable from affiliate										0
Receivable from affiliate									0
Other									(4)	(8)	(4)
Cash used by continuing operations									118	(168)	394
Cash provided/(used) by discontinued operations									471	(60)	646
Net Cash (Used)/Provided by Financing Activities									589	(228)	1,040
Effect of exchange rate changes on cash and cash equivalents									1	(1)	1
Change in Cash from discontinued operations									31	(388)	564
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									(387)	(110)	247
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	38				425				38	425	535
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				425				535	425	535	288
NRG Energy, Inc. (Note Issuer)
Cash Flows from Operating Activities
Net (Loss)/Income									374	(2,169)	(718)
(Loss)/income from discontinued operations, net of income tax									(329)	(663)	(21)
Net Income/(Loss) from Continuing Operations									703	(1,506)	(697)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates									(1)	90	86
Depreciation, amortization and accretion									33	32	26
Provision for bad debts									0	12	0
Amortization of nuclear fuel									0	0	0
Amortization of financing costs and debt discount/premiums									23	16	20
Adjustment for debt extinguishment									44	49	138
Amortization of intangibles and out-of-market contracts									0	0	0
Amortization of unearned equity compensation									25	35	10
Net (gain)/loss on sale of assets and equity/cost method investments									1	0	69
Impairment losses									0	4	16
Changes in derivative instruments									11	(4)	(36)
Changes in deferred income taxes and liability for uncertain tax benefits									(372)	322	(60)
Changes in collateral deposits in support of risk management activities									0	0	0
Changes in nuclear decommissioning trust liability									0	0	0
GenOn settlement, net of insurance proceeds									(63)
Net loss on deconsolidation of Agua Caliente and Ivanpah projects									0
Changes in other working capital									(1,621)	62	(256)
Cash provided/(used) by continuing operations									(1,217)	(888)	(684)
Cash provided by discontinued operations									0	0	0
Net Cash Provided by Operating Activities									(1,217)	(888)	(684)
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired									0	0	0
Capital expenditures									(45)	(31)	(46)
Proceeds from renewable energy grants										0	0
Net proceeds from sale/(purchases) of emission allowances									0
Net proceeds from sale of emission allowances										0	0
Investments in nuclear decommissioning trust fund securities									0	0	0
Proceeds from sales of nuclear decommissioning trust fund securities									0	0	0
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees									1,542	343	185
Deconsolidation of Agua Caliente and Ivanpah projects									0
Changes in investments in unconsolidated affiliates									0	0	0
Net (contributions to)/distributions from discontinued operations									0	150	(58)
Other									(6)	0	0
Cash provided/(used) by continuing operations									1,491	462	81
Cash used by discontinued operations									0	0	0
Net Cash Used by Investing Activities									1,491	462	81
Cash Flows from Financing Activities
Payments (for)/from intercompany loans									1,588	1,564	1,481
Payments of dividends to preferred and common stockholders									(37)	(38)	(76)
Payment for preferred shares									(1,250)
Payments for preferred shares											(226)
Payments for debt extinguishment costs									(32)	(42)	(121)
Net distributions to noncontrolling interests from subsidiaries									0	0	0
Proceeds/(payments) from issuance of common stock									21	(2)	1
Proceeds from issuance of long-term debt									937	1,084	4,141
Payments of debt issuance costs									(19)	(16)	(61)
Payments for short and long-term debt									(1,596)	(1,701)	(4,923)
Receivable from affiliate										(125)
Receivable from affiliate									(26)
Other									0	0	0
Cash used by continuing operations									(414)	724	216
Cash provided/(used) by discontinued operations									0	0	0
Net Cash (Used)/Provided by Financing Activities									(414)	724	216
Effect of exchange rate changes on cash and cash equivalents									0	0	0
Change in Cash from discontinued operations									0	0	0
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash									(140)	298	(387)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$ 480				$ 620				480	620	322
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period				$ 620				$ 322	$ 620	$ 322	$ 709

VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Allowance for doubtful accounts, deducted from accounts receivable
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	$ 28	$ 28	$ 21
Charged to Costs and Expenses	83	57	55
Charged to Other Accounts	0	0	0
Deductions	(79)	(57)	(48)
Balance at End of Period	32	28	28
Income tax valuation allowance, deducted from deferred tax assets
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	1,863	4,116	3,575
Charged to Costs and Expenses	1,934	(151)	306
Charged to Other Accounts	(128)	(15)	235
Deductions	125	(2,087)	0
Balance at End of Period	$ 3,794	$ 1,863	$ 4,116

Fair Value of Financial Instruments - Assets and Liabilities Measured and Recorded at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	$ 663	$ 692
Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	1,042	744
Derivative liabilities	977	674
Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	39	39
Derivative liabilities		6
Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	19	47
U.S. government and federal agency obligations
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	46	43
Federal agency mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	100	82
Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	22	14
Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	96	99
Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	376	402
Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	4	5
Level 1 \| Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Equity securities-nuclear trust fund investments	0
Level 2 \| Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Equity securities-nuclear trust fund investments	0
Level 3 \| Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Equity securities-nuclear trust fund investments	0
Fair Value, Measurements, Recurring
Investment in available-for-sale securities (classified within other non-current assets):
Investments in securities (classified within other current or non-current assets)	39	39
U.S. government and federal agency obligations	1	1
Total assets	1,792	1,523
Total liabilities	977	680
Fair Value, Measurements, Recurring \| Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	1,042	744
Derivative liabilities	977	674
Fair Value, Measurements, Recurring \| Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	39	39
Derivative liabilities		6
Fair Value, Measurements, Recurring \| Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	19	47
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	46	43
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	100	82
Fair Value, Measurements, Recurring \| Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	22	14
Fair Value, Measurements, Recurring \| Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	96	99
Fair Value, Measurements, Recurring \| Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Nuclear trust fund investments	312	334
Equity securities-nuclear trust fund investments	8	8
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	4	5
Fair Value, Measurements, Recurring \| Equity securities-nuclear trust fund investments
Investment in available-for-sale securities (classified within other non-current assets):
Equity securities-nuclear trust fund investments	64	68
Fair Value, Measurements, Recurring \| Level 1
Investment in available-for-sale securities (classified within other non-current assets):
Investments in securities (classified within other current or non-current assets)	2	3
U.S. government and federal agency obligations	1	1
Total assets	517	616
Total liabilities	224	257
Fair Value, Measurements, Recurring \| Level 1 \| Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	137	191
Derivative liabilities	224	257
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
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	19	45
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	46	42
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	312	334
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):
Investments in securities (classified within other current or non-current assets)	18	17
U.S. government and federal agency obligations	0	0
Total assets	1,075	768
Total liabilities	664	364
Fair Value, Measurements, Recurring \| Level 2 \| Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	796	509
Derivative liabilities	664	358
Fair Value, Measurements, Recurring \| Level 2 \| Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	39	39
Derivative liabilities		6
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	0	2
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	0	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	100	82
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	22	14
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	96	99
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	4	5
Fair Value, Measurements, Recurring \| Level 3
Investment in available-for-sale securities (classified within other non-current assets):
Investments in securities (classified within other current or non-current assets)	19	19
U.S. government and federal agency obligations	0	0
Total assets	128	63
Total liabilities	89	59
Fair Value, Measurements, Recurring \| Level 3 \| Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets	109	44
Derivative liabilities	89	59
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
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