NRG Energy (NRG) 10-K 1 Mar 21 2020 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2020	Mar. 01, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-15891
Entity Registrant Name	NRG Energy, Inc
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	41-1724239
Entity Address, Address Line One	804 Carnegie Center
Entity Address, City or Town	Princeton
Entity Address, State or Province	NJ
Entity Address, Postal Zip Code	08540
City Area Code	609
Local Phone Number	524-4500
Title of 12(b) Security	Common Stock, par value $0.01
Trading Symbol	NRG
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 6,941,658,699
Entity Common Stock, Shares Outstanding		244,687,907
Documents Incorporated by Reference	Portions of the Registrant's definitive Proxy Statement relating to its 2021 Annual Meeting of Stockholders are incorporated by reference into Part III of this Annual Report on Form 10-K
Entity Central Index Key	0001013871
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Revenues
Total operating revenues	$ 9,093	$ 9,821	$ 9,478
Operating Costs and Expenses
Cost of operations	6,540	7,303	7,108
Depreciation and amortization	435	373	421
Impairment losses	75	5	99
Selling, general and administrative costs	933	827	799
Reorganization costs	0	23	90
Development costs	8	7	11
Total operating costs and expenses	7,991	8,538	8,528
Gain on sale of assets	3	7	32
Operating Income	1,105	1,290	982
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	17	2	9
Impairment losses on investments	(18)	(108)	(15)
Other income, net	67	66	18
Loss on debt extinguishment, net	(9)	(51)	(44)
Interest expense	(401)	(413)	(483)
Total other expense	(344)	(504)	(515)
Income from Continuing Operations Before Income Taxes	761	786	467
Income tax expense/(benefit)	251	(3,334)	7
Income from Continuing Operations	510	4,120	460
Income from discontinued operations, net of income tax	0	321	(192)
Net Income	510	4,441	268
Less: Net income attributable to noncontrolling interest and redeemable interests	0	3	0
Net Income Attributable to NRG Energy, Inc.	$ 510	$ 4,438	$ 268
Earnings/(Loss) Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic (in shares)	245,000,000	262,000,000	304,000,000
Income from continuing operations per weighted average common share —basic (in usd per share)	$ 2.08	$ 15.71	$ 1.51
Income/(loss) from discontinued operations per weighted average common share — basic (in usd per share)	0	1.23	(0.63)
Net Income per Weighted Average Common Share - Basic (in usd per share)	$ 2.08	$ 16.94	$ 0.88
Weighted average number of common shares outstanding — diluted (in shares)	246,000,000	264,000,000	308,000,000
Income from continuing operations per weighted average common share — diluted (in usd per share)	$ 2.07	$ 15.59	$ 1.49
Income/(loss) from discontinued operations per weighted average common share — diluted (in usd per share)	0	1.22	(0.62)
Net Income per Weighted Average Common Share - Diluted (in usd per share)	$ 2.07	$ 16.81	$ 0.87

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net Income	$ 510	$ 4,441	$ 268
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net of income tax	0	0	23
Foreign currency translation adjustments, net of income tax	8	(1)	(11)
Available-for-sale securities, net of income tax	0	(19)	1
Defined benefit plans, net of income tax	(22)	(78)	(35)
Other comprehensive (loss)	(14)	(98)	(22)
Comprehensive Income	496	4,343	246
Less: Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests	0	3	14
Comprehensive Income Attributable to NRG Energy, Inc.	$ 496	$ 4,340	$ 232

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 3,905	$ 345
Funds deposited by counterparties	19	32
Restricted cash	6	8
Accounts receivable, net	904	1,025
Inventory	327	383
Derivative instruments	560	860
Cash collateral posted in support of energy risk management activities	50	190
Prepayments and other current assets	257	245
Total current assets	6,028	3,088
Property, plant and equipment, net	2,547	2,593
Other Assets
Equity investments in affiliates	346	388
Operating lease right-of-use assets, net	301	464
Goodwill	579	579
Intangible assets, net	668	789
Nuclear decommissioning trust fund	890	794
Derivative instruments	261	310
Deferred income taxes	3,066	3,286
Other non-current assets	216	240
Total other assets	6,327	6,850
Total Assets	14,902	12,531
Current Liabilities
Current portion of long-term debt and finance lease	1	88
Current portion of operating lease liabilities	69	73
Accounts payable	649	722
Derivative instruments	499	781
Cash collateral received in support of energy risk management activities	19	32
Accrued expenses and other current liabilities	678	663
Total current liabilities	1,915	2,359
Other Liabilities
Long-term debt and finance lease	8,691	5,803
Non-current operating lease liabilities	278	483
Nuclear decommissioning reserve	303	298
Nuclear decommissioning trust liability	565	487
Derivative instruments	385	322
Deferred income taxes	19	17
Other non-current liabilities	1,066	1,084
Total other liabilities	11,307	8,494
Total Liabilities	13,222	10,853
Redeemable noncontrolling interest in subsidiaries	0	20
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,057,848 and 421,890,790 shares issued; and 244,231,933 and 248,996,189 shares outstanding at December 31, 2020 and 2019	4	4
Additional paid-in capital	8,517	8,501
Accumulated deficit	(1,403)	(1,616)
Treasury stock, at cost; 178,825,915 and 172,894,601 shares at December 31, 2020 and 2019	(5,232)	(5,039)
Accumulated other comprehensive loss	(206)	(192)
Total Stockholders' Equity	1,680	1,658
Total Liabilities and Stockholders' Equity	$ 14,902	$ 12,531

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
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)	423,057,848	421,890,790
Common stock, shares outstanding (in shares)	244,231,933	248,996,189
Treasury stock, shares (in shares)	178,825,915	172,894,601

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Flows from Operating Activities
Net Income	$ 510	$ 4,441	$ 268
Income/(loss) from discontinued operations, net of income tax	0	321	(192)
Income from continuing operations	510	4,120	460
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions from and equity in earnings of unconsolidated affiliates	45	14	46
Depreciation and amortization	435	373	421
Accretion of asset retirement obligations	45	51	38
Provision for credit losses	108	95	85
Amortization of nuclear fuel	54	52	48
Amortization of financing costs and debt discounts	48	26	29
Loss on debt extinguishment, net	9	51	44
Amortization of emission allowances, out-of-market contracts and REC retirements	70	72	71
Amortization of unearned equity compensation	22	20	25
Net gain on sale of assets and disposal of assets	(23)	(23)	(49)
Impairment losses	93	113	114
Changes in derivative instruments	137	34	37
Changes in deferred income taxes and liability for uncertain tax benefits	228	(3,353)	5
Changes in collateral deposits in support of risk management activities	127	105	(105)
Changes in nuclear decommissioning trust liability	51	37	60
Oil lower of cost or market adjustment	29	0	2
GenOn settlement, net of insurance proceeds	0	0	(63)
Net loss on deconsolidation of Agua Caliente and Ivanpah projects	0	0	13
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects:
Accounts receivable - trade	0	5	(83)
Inventory	27	22	29
Prepayments and other current assets	4	29	(41)
Accounts payable	(56)	(177)	113
Accrued expenses and other current liabilities	(42)	(75)	(192)
Other assets and liabilities	(84)	(186)	(104)
Cash provided by continuing operations	1,837	1,405	1,003
Cash provided by discontinued operations	0	8	374
Net Cash Provided by Operating Activities	1,837	1,413	1,377
Cash Flows from Investing Activities
Payments for acquisitions of assets, businesses and leases	(284)	(355)	(243)
Capital expenditures	(230)	(228)	(388)
Net (purchases)/sales of emissions allowances	(10)	11	19
Investments in nuclear decommissioning trust fund securities	(492)	(416)	(572)
Proceeds from sales of nuclear decommissioning trust fund securities	439	381	513
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	81	1,294	1,564
Deconsolidations of Agua Caliente and Ivanpah projects	0	0	(268)
Changes in investments in unconsolidated affiliates	2	(91)	(39)
Net contributions to discontinued operations	0	(44)	(60)
Other	0	6	(6)
Cash (used)/provided by continuing operations	(494)	558	520
Cash used by discontinued operations	0	(2)	(725)
Net Cash (Used)/Provided by Investing Activities	(494)	556	(205)
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt	3,234	1,833	1,100
Payments for short and long-term debt	(335)	(2,571)	(1,734)
Net proceeds of Revolving Credit Facility	(83)	83	0
Payments of debt issuance costs	(75)	(35)	(19)
Payments of dividends to common stockholders	(295)	(32)	(37)
Payments for share repurchase activity	(229)	(1,440)	(1,250)
Payments for debt extinguishment costs	(5)	(26)	(32)
Purchase of and distributions to noncontrolling interests from subsidiaries	(2)	(2)	(16)
Proceeds from issuance of common stock	1	3	21
Receivable from affiliate	0	0	(26)
Other	(7)	(4)	(4)
Cash provided/(used) by continuing operations	2,204	(2,191)	(1,997)
Cash provided by discontinued operations	0	43	471
Net Cash (Used)/Provided by Financing Activities	2,204	(2,148)	(1,526)
Effect of exchange rate changes on cash and cash equivalents	(2)	0	1
Change in Cash from discontinued operations	0	49	120
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	3,545	(228)	(473)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	385	613	1,086
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$ 3,930	$ 385	$ 613

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions		Total	Cumulative Effect, Period of Adoption, Adjustment	NRG Yield, Inc.	Common Stock	Additional Paid-In Capital	Additional Paid-In CapitalNRG Yield, Inc.	Accumulated Deficit	Accumulated DeficitCumulative Effect, Period of Adoption, Adjustment	Treasury Stock	Accumulated Other Comprehensive Loss	Noncon- trolling Interest	Noncon- trolling InterestNRG Yield, Inc.
Increase (Decrease) in Stockholders' Equity
Adoption of new accounting standards		$ 1,968	$ 15		$ 4	$ 8,376		$ (6,268)	$ 15	$ (2,386)	$ (72)	$ 2,314
Beginning balance at Dec. 31, 2017		1,968	15		4	8,376		(6,268)	15	(2,386)	(72)	2,314
Increase (Decrease) in Stockholders' Equity
Net loss (income)		294						268				26
Other comprehensive loss		(22)									(22)
Sale of assets to NRG Yield, Inc				$ 16			$ 8						$ 8
Shares reissuance for ESPP		2				(2)				4
Share repurchases		(1,250)								(1,250)
Equity-based awards activity, net		6				6
Issuance of common stock		21				21
Common stock dividends	[1]	(37)						(37)
Distributions to noncontrolling interest and dividends paid		(43)		$ (61)								(43)	$ (61)
Contributions from noncontrolling interests		304										304
Adoption of new accounting standards		(1,234)	$ 15		4	8,510		(6,022)	$ 15	(3,632)	(94)	0
Sale of NRG Yield and other business		(2,548)										(2,548)
Equity component of convertible senior notes		101				101
Ending 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		(1,234)			4	8,510		(6,022)		(3,632)	(94)	0
Net loss (income)		4,438						4,438
Other comprehensive loss		(98)									(98)
Shares reissuance for ESPP		3				1				2
Share repurchases		(1,409)								(1,409)
Equity-based awards activity, net		(16)				(16)
Issuance of common stock		6				6
Common stock dividends	[1]	(32)						(32)
Adoption of new accounting standards		1,658			4	8,501		(1,616)		(5,039)	(192)	0
Ending balance at Dec. 31, 2019		1,658			4	8,501		(1,616)		(5,039)	(192)	0
Increase (Decrease) in Stockholders' Equity
Adoption of new accounting standards		1,658			4	8,501		(1,616)		(5,039)	(192)	0
Net loss (income)		510						510
Other comprehensive loss		(14)									(14)
Shares reissuance for ESPP		4								4
Share repurchases		(197)								(197)
Equity-based awards activity, net		(3)				(3)
Issuance of common stock		1				1
Common stock dividends	[1]	(297)						(297)
Adoption of new accounting standards		1,658			4	8,517		(1,403)		(5,232)	(206)	0
Repurchase of partners' equity interest in VIE		18
Ending balance at Dec. 31, 2020		1,680			4	8,517		(1,403)		(5,232)	(206)	0
Increase (Decrease) in Stockholders' Equity
Adoption of new accounting standards		$ 1,680			$ 4	$ 8,517		$ (1,403)		$ (5,232)	$ (206)	$ 0
[1]	Dividends per common share were $1.20 for the year ended December 31, 2020 and $0.12 for each of the years ended December 31, 2019 and 2018

CONSOLIDATED STATEMENTS OF ST_2

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Stockholders' Equity [Abstract]
Dividends paid per share (in usd per share)	$ 1.20	$ 0.12	$ 0.12

Nature of Business

Nature of Business	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of Business General NRG Energy, Inc., or NRG or the Company, is an integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to customers by producing and selling energy and related products and services in major competitive power and gas markets in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. NRG is a customer-centric business focused on perfecting the integrated model by balancing retail load with generation supply within its deregulated markets. As of December 31, 2020, the Company sold energy, services, and innovative, sustainable products and services directly to retail customers under the names NRG, Reliant, Green Mountain Energy, Stream and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation. NRG also conducts business under the brand name of Direct Energy as a result of the Company's acquisition of Direct Energy, a North American subsidiary of Centrica plc, on January 5, 2021. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. Following the acquisition, the Company serves more than 6 million customers. In addition, Direct Energy is a participant in the wholesale gas and power markets in the United States and Canada. Note 4, Acquisitions, Discontinued Operations and Dispositions for further discussion of the acquisition of Direct Energy. The Company began managing its integrated model based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of 2020. The Company's updated segment structure reflects how management makes financial decisions and allocates resources. The Company's businesses are segregated as follows: • Texas, which includes all activity related to customer, plant and market operations in Texas; • East, which includes the remaining activity related to customer operations and all activity related to plant and market operations in the East; • West/Other, which includes the following assets and activities: (i) all activity related to plant and market operations in the West, (ii) activity related to the Cottonwood power plant that was sold to Cleco on February 4, 2019 and is being leased back until 2025, (iii) the remaining renewables activity, including the Company’s equity method investments in Ivanpah Master Holdings, LLC and Agua Caliente (which was sold on February 3, 2021), the remaining Home Solar assets (which were primarily sold on November 13, 2020) and the NFL stadium solar generating assets, and (iv) activity related to the Company’s equity method investment for the Gladstone power plant in Australia; and • Corporate activities. All affected disclosures presented herein have been recast to reflect these changes for all periods presented. For further discussion of segment reporting, refer to Note 20, Segment Reporting . The acquired operations of Direct Energy will be integrated into the existing NRG segment structure. Domestic customer and market operations will be combined into the corresponding geographical segments of Texas, East and West/Other. The East segment will also include the deregulated customer and market operations of Canada. The West/Other segment will also include activity related to the regulated operations in Alberta, Canada and the services businesses. COVID-19 In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the COVID-19 outbreak a national emergency. Electricity was deemed a 'critical and essential business operation' under various state and federal governmental COVID-19 mandates. NRG had activated its Crisis Management Team ("CMT") in January 2020 to proactively manage the Company's response to the impacts of COVID-19. NRG continues to remain focused on protecting the health and well-being of its employees, while supporting its customers and the communities in which it operates and assuring the continuity of its operations. In June 2020, summer-critical office employees returned to the offices and safety protocols were successfully implemented. The Company continues to maintain certain restrictions on business travel and face-to-face sales channels, remote work practices remain in place and there are enhanced cleaning and hygiene protocols in all of its facilities. In addition, select essential employees and contractors are continuing to report to plant and certain office locations. The Company also continues to require pre-entry screening, including temperature checks, separation of work crews, additional personal protective equipment for employees and contractors when social distancing cannot be maintained, and a ban on all non-essential visitors. The Company has not experienced any material disruptions in its ability to continue its business operations to date. The first COVID-19 vaccine became available in the United States in December 2020. NRG continues to advocate alongside state and federal trade groups for the high prioritization of essential electric industry personnel for inoculation against COVID-19. States are receiving weekly doses of vaccines and allocating those doses to frontline healthcare workers, elderly populations and high risk individuals. NRG continues to monitor state information, as well as dosage and allocation numbers to anticipate the latest timing of vaccine distribution to our essential employees. The Company will continue to evaluate additional return to normal work operations on a location-by-location basis as COVID-19 conditions evolve. Discontinued Operations On December 31, 2018, as described in Note 4, 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 was recast in 2018 to reflect the presentation of these entities as discontinued operations. On August 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated. 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, (In millions) 2020 2019 2018 Income from continuing operations, net of income tax $ 510 $ 4,117 $ 465 Income/(loss) from discontinued operations, net of income tax — 321 (197) Net income attributable to NRG Energy, Inc. stockholders $ 510 $ 4,438 $ 268 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 Credit Losses On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments , or ASU No. 2016-13, using the modified retrospective approach. Following the adoption of the new standard, the Company’s process of estimating expected credit losses remains materially consistent with its historical practice. Information prior to January 1, 2020, which was previously referred to as the allowance and provision for bad debt, has not been restated and continues to be reported under the accounting standards in effect for that period. Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues an allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and industrial customers. The Company writes off customer contract receivable balances against the allowance for credit losses when it is determined a receivable is uncollectible. The following table represents the activity in the allowance for credit losses for the year ended December 31, 2020: (In millions) Year Ended December 31, 2020 Beginning balance $ 43 Provision for credit losses 108 Write-offs (101) Recoveries collected 17 Ending balance $ 67 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, (In millions) 2020 2019 2018 Cash and cash equivalents $ 3,905 $ 345 $ 563 Funds deposited by counterparties 19 32 33 Restricted cash 6 8 17 Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows $ 3,930 $ 385 $ 613 Restricted cash consists primarily of funds held within the Company's projects that are restricted in their use. 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 11, 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, 2020, 2019 and 2018, was $2 million, $3 million and $7 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, or as an asset if the issuance costs relate to revolving debt agreements or certain other financing arrangements. 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, 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, 2020 and 2019, the Company had accumulated amortization related to its intangible assets of $1.4 billion and $1.3 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, Intangibles-Goodwill and Other , or 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 indicating that it is more-likely-than-not that no impairment occurred, 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 12, Goodwill and Other Intangibles. Income Taxes The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or 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 expected to be in effect when the deferred tax is realized. 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 is the amount of benefit that has surpassed the more-likely-than-not threshold, as it 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 21, Income Taxes , changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax (benefit)/expense. 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 or more than market are amortized to cost of operations 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 842, 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. 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 842 . 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 finance lease. Contingent rental income under ASC 840 was $104 million for the year ended December 31, 2018. Gross Receipts and Sales Taxes In connection with its retail sales, 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, 2020, 2019 and 2018, the Company's revenues and cost of operations included gross receipts taxes of $107 million, $109 million and $99 million, respectively. Additionally, the Company records sales taxes collected from its taxable retail 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. Purchased Energy and Other Cost of Sales for Customer Operations The cost of energy for electricity sales and services to retail customers is included in cost of operations and is based on actual and estimated supply volumes for the applicable reporting period. A portion of the cost of energy, $98 million, $103 million and $105 million as of December 31, 2020, 2019 and 2018, 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, and other energy related commodities 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. The Company had no cash flow hedges as of December 31, 2020. 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, 2020, 2019 and 2018, amounts recognized as foreign currency transaction gains/(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2020, 2019 and 2018 were $(2) million, $(13) million and $(13) 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 5, 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 5, 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 15, 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 , or ASC 715 . 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 performance stock units is estimated on the date of grant using a Monte Carlo valuation model. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's deferred stock units. The fair value of the Company's restricted stock units is derived from the closing price of NRG's common stock at the grant date. 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 represented third-party interests in the net assets under certain tax equity arrangements, which were consolidated by the Company, that had been entered into to finance the cost of solar energy systems under operating leases. The Company determined that the provisions in the contractual agreements of these structures represented substantive profit sharing arrangements. Further, the Company had determined that the appropriate methodology for calculating the redeemable noncontrolling interest that reflected the substantive profit sharing arrangements was a balance sheet approach that utilized the HLBV method. Under the HLBV method, the amounts reported as redeemable noncontrolling interests represented the amounts the investors that were 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. The investors’ interests in the results of operations of the funding structures were determined as 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 included estimated calculations of taxable income or losses for each reporting period. During the first quarter of 2020, the Company repurchased its partners' equity interest as further described in Note 18, Investments Accounted for by the Equity Method and Variable Interest Entities . The Company has no remaining tax equity arrangements as of December 31, 2020. Redeemable Noncontrolling Interest To the extent that the third-party has the right to redeem their interests for cash or other assets, the Company had included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet. During the first quarter of 2020, the Company repurchased its partners' equity interest. The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2020, 2019 and 2018. (In millions) 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 Distributions to redeemable noncontrolling interest (2) Net income attributable to redeemable noncontrolling interest - continuing operations 3 Balance as of December 31, 2019 20 Repurchase of redeemable noncontrolling interest (20) Balance as of December 31, 2020 $ — (a) See Note 4, 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 simultaneously leases back the same asset to the Company. If the seller-lessee transfers control of the underlying assets to the buyer-lessor, the arrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as operating leases on the Company's consolidated balance sheets. See Note 10, Leases, for further discussion. Marketing and Advertising Costs The Company expenses its marketing and advertising costs as incurred and includes them 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, 2020, 2019 and 2018 were $74 million, $66 million and $73 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. There were no reorganization costs for the year ended December 31, 2020. Reorganization costs for the years ended December 31, 2019 and 2018 were $23 million and $90 million, respectively. Business Combinations The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805, which 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. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination. In addition, transaction costs are expensed as incurred. Use of Estim

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition Revenue from Contracts with Customers On January 1, 2018, the Company adopted the guidance in ASC 606, Revenue from Contracts with Customers, or 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 $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 Company's policies with respect to its various revenue streams are detailed below. The Company generally 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 Revenue 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 and natural gas contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity and natural gas products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligations 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, utilities, 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 and natural gas 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 consist of revenues billed to a third party at either market or negotiated contract terms 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 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 used to hedge the sale of electricity are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815. Capacity Revenue The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE and NYISO. Capacity revenues also include revenues billed to a third party at either market or negotiated contract terms 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 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. Performance Obligations As of December 31, 2020, estimated future fixed fee performance obligations are $668 million, $289 million, $47 million, $36 million and $20 million for fiscal years 2021, 2022, 2023, 2024 and 2025, respectively. These performance obligations are for cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non performance. 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 Revenue The following tables represent the Company’s disaggregation of revenue from contracts with customers for the years ended December 31, 2020, 2019 and 2018: For the Year Ended December 31, 2020 (In millions) Texas East West/Other Corporate/Eliminations Total Retail revenue Mass Market $ 5,027 $ 1,306 $ — $ (2) $ 6,331 Business Solutions 1,034 95 — — 1,129 Total retail revenue 6,061 1,401 — (2) 7,460 Energy revenue (a) 24 183 333 (1) 539 Capacity revenue (a) — 620 61 (1) 680 Mark-to-market for economic hedging activities (b) 2 88 (3) 8 95 Other revenue (a) 222 62 43 (8) 319 Total operating revenue 6,309 2,354 434 (4) 9,093 Less: Lease revenue — 1 17 — 18 Less: Realized and unrealized ASC 815 revenue 30 314 38 3 385 Total revenue from contracts with customers $ 6,279 $ 2,039 $ 379 $ (7) $ 8,690 (a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: (In millions) Texas East West/Other Corporate/Eliminations Total Energy revenue $ — $ 67 $ 43 $ (5) $ 105 Capacity revenue — 156 — — 156 Other revenue 28 3 (2) — 29 (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 For the Year Ended December 31, 2019 (In millions) Texas East West/Other Corporate/Eliminations Total Retail revenue Mass Market $ 5,027 $ 1,230 $ — $ (3) $ 6,254 Business Solutions 1,205 74 — — 1,279 Total retail revenue 6,232 1,304 — (3) 7,533 Energy revenue (a) 529 322 318 — 1,169 Capacity revenue (a) — 664 36 — 700 Mark-to-market for economic hedging activities (b) 47 (29) 16 (1) 33 Other revenue (a)(c) 261 58 70 (3) 386 Total operating revenue 7,069 2,319 440 (7) 9,821 Less: Lease revenue — 1 19 — 20 Less: Realized and unrealized ASC 815 revenue 1,562 183 67 (2) 1,810 Total revenue from contracts with customers $ 5,507 $ 2,135 $ 354 $ (5) $ 7,991 (a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: (In millions) Texas East West/Other Corporate/Eliminations Total Energy revenue $ 1,459 $ 98 $ 39 $ (1) $ 1,595 Capacity revenue — 109 — — 109 Other revenue 56 5 12 — 73 (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 For the Year Ended December 31, 2018 (In millions) Texas East West/Other Corporate/Eliminations Total Retail revenue Mass Market $ 4,618 $ 974 $ — $ (1) $ 5,591 Business Solutions 1,238 65 — — 1,303 Total retail revenue 5,856 1,039 — (1) 6,894 Energy revenue (a) 371 546 566 13 1,496 Capacity revenue (a) — 746 79 — 825 Mark-to-market for economic hedging activities (b) (77) (35) (5) (13) (130) Other revenue (a)(c) 251 75 84 (17) 393 Total operating revenue 6,401 2,371 724 (18) 9,478 Less: Lease revenue 1 1 19 — 21 Less: Realized and unrealized ASC 815 revenue 1,096 210 2 1 1,309 Total revenue from contracts with customers $ 5,304 $ 2,160 $ 703 $ (19) $ 8,148 (a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: (In millions) Texas East West/Other Corporate/Eliminations Total Energy revenue $ 1,131 $ 90 $ (2) $ 14 $ 1,233 Capacity revenue — 137 — — 137 Other revenue 42 17 9 1 69 (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 Contract Balances The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31, 2020 and 2019: (In millions) December 31, 2020 December 31, 2019 Deferred customer acquisition costs $ 113 $ 133 Accounts receivable, net - Contracts with customers 866 1,002 Accounts receivable, net - Derivative instruments 33 18 Accounts receivable, net - Affiliate 5 5 Total accounts receivable, net $ 904 $ 1,025 Unbilled revenues (included within Accounts receivable, net - Contracts with customers) $ 393 $ 402 Deferred revenues (a) $ 60 $ 82 (a) Deferred revenues from contracts with customers for the years ended December 31, 2020 and 2019 were approximately $31 million and $24 million, respectively. The revenue recognized from contracts with customers during both years ended December 31, 2020 and 2019 relating to the deferred revenue balance at the beginning of each period was $13 million. The change in deferred revenue balances during the years ended December 31, 2020 and 2019 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred. 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.

Acquisitions, Discontinued Oper

Acquisitions, Discontinued Operations and Dispositions Acquisitions, Discontinued Operations and Dispositions	12 Months Ended
	Dec. 31, 2020
Discontinued Operations and Disposal Groups [Abstract]
Acquisitions, Discontinued Operations and Dispositions	Acquisitions, Discontinued Operations and Dispositions Acquisitions Direct Energy Acquisition On January 5, 2021 (the "Acquisition Closing Date"), the Company acquired all of the issued and outstanding common shares of Direct Energy, a North American subsidiary of Centrica plc. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition increased NRG's retail portfolio by over 3 million customers and strengthens its integrated model. It also broadens the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business. The Company paid an aggregate purchase price of $3.625 billion in cash, subject to a purchase price adjustment of $77 million. The Company funded the purchase price using a combination of $715 million of cash on hand, $166 million from a draw on its Revolving Credit Facility (of which $107 million was used to fund acquisition costs and financing fees that are not included in the aggregate purchase price above) as well as approximately $2.9 billion in secured and unsecured corporate debt issued in December 2020. The Company also increased its collective collateral facilities by $3.4 billion as of the Acquisition Closing Date to meet the additional liquidity requirements related to the acquisition, as detailed in the following table: (In millions) December 31, 2020 Revolving Credit Facility commitment increase (a) $ 802 Revolving Credit Facility new tranche (a) 273 Credit default swap facility 150 Revolving accounts receivable financing facility 750 Repurchase facility 75 Facility agreement in connection with the sale of pre-capitalized trust securities (a) 874 Bilateral letter of credit facilities 475 Total Increases to Liquidity and Collateral Facilities $ 3,399 (a) Available upon the Acquisition Closing Date For further discussion see Note 13, Receivables Securitization and Repurchase Facility and Note 14, Long-term Debt and Finance Leases . Acquisition costs of $17 million for the year ended December 31, 2020 are included in selling, general and administrative costs in the Company's consolidated statement of operations. The acquisition will be recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair value of certain net assets acquired and the amount of goodwill to be recognized are still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The purchase price is provisionally allocated as follows: (In millions) Assets Cash and cash equivalents $ 152 Current assets 3,374 Property, plant and equipment 166 Goodwill and other intangibles (a) 3,446 Other non-current assets 687 Total assets acquired 7,825 Liabilities Current liabilities 3,085 Non-current liabilities 1,038 Total liabilities assumed 4,123 Direct Energy Purchase Price $ 3,702 (a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of Direct Energy with NRG's existing businesses. Midwest Generation Lease Purchase — On September 29, 2020, Midwest Generation acquired all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $260 million. The purchase was funded with cash-on-hand. Upon closing, lease expense related to these facilities, which totaled approximately $14 million in 2019, and the operating lease liability of $148 million were eliminated. Stream Energy Acquisition — On August 1, 2019, the Company completed the acquisition of Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $329 million, including working capital and other adjustments of approximately $29 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers. The purchase price was allocated as follows: (In millions) Account receivable $ 98 Accounts payable (73) Other net current and non-current working capital 5 Marketing partnership 154 Customer relationships 85 Trade name 28 Other intangible assets 26 Goodwill (a) 6 Stream Purchase Price $ 329 (a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of Stream Energy with NRG's existing businesses. Goodwill of $5 million and $1 million was assigned to the Texas and East segments, respectively, and is not deductible for tax purposes 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, including working capital and other adjustments of $48 million. The acquisition increased NRG's retail portfolio by approximately 395,000 RCEs or 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 (a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of XOOM Energy with NRG's existing businesses. Goodwill of $28 million and $6 million was assigned to the Texas and East segments, respectively, and is deductible for tax purposes Small Book Acquisitions — In 2020, the Company acquired multiple books of customers totaling approximately 56,000 customers for $22 million. During 2019, the Company acquired several books of customers totaling approximately 72,000 customers for $17 million, of which $13 million was paid in 2019. During 2018, the Company acquired several books of customers totaling approximately 115,000 customers, along with brand names, for $44 million, of which $40 million was paid in 2018 and $2 million was paid in 2019. The majority of the purchase price for the 2020, 2019 and 2018 book acquisitions were allocated to acquired intangible assets. Discontinued Operations Sale of South Central Portfolio On February 4, 2019, the Company completed the sale of its South Central Portfolio to Cleco for cash consideration of $1 billion excluding working capital and other adjustments. 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 were reclassified as discontinued operations at December 31, 2018. In connection with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested business, which have been substantially completed in 2020. The South Central Portfolio includes the 1,153 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 did not use held-for-sale or discontinued operations treatment in accounting for the Cottonwood facility. Summarized results of South Central discontinued operations were as follows: Year Ended December 31, (In millions) 2019 2018 Operating revenues $ 31 $ 410 Operating costs and expenses (23) (346) Other income — 2 Gain from operations of discontinued components 8 66 Gain on disposal of discontinued operations, net of tax 20 — Gain from discontinued operations, including disposal, net of tax $ 28 $ 66 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 were 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 in 2018, which concluded in 2020. During the year ended December 31, 2019, the Company recorded an adjustment to reduce the purchase price by $15 million in connection with the completion of the Patriot Wind project. During the year ended December 31, 2019, the Company reduced the liability related to the indemnification of NRG Yield for any increase in property taxes for certain solar properties by $22 million due to updated estimates. Carlsbad On February 6, 2018, NRG entered into an agreement with NRG Yield and GIP to sell 100% of its membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, for $385 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. At the time of the sale of NRG Yield and the Renewables Platform in August 2018, the Company concluded that the Carlsbad project met the criteria for discontinued operations and accordingly, all current and prior period results for Carlsbad were reclassified as discontinued operations. The transaction closed on February 27, 2019. Carlsbad will continue to have a ground lease and easement agreement with NRG with an initial term ending in 2039 and two ten Summarized results of NRG Yield, Inc. and Renewables Platform and Carlsbad discontinued operations were as follows: (In millions) 2019 2018 Operating revenues $ 19 $ 909 Operating costs and expenses (9) (661) Other expenses (5) (174) Gain/(loss) from operations of discontinued components, before tax 5 74 Income tax expense — 4 Gain/(loss) from discontinued operations, net of tax 5 70 Gain/(loss) on disposal of discontinued operations, net of tax 265 (134) Income/(expense) from California property tax indemnification 22 (153) Income/(expense) from other commitments, indemnification and fees 4 (75) Income/(loss) on disposal of discontinued operations, net of tax 291 (362) Income/(loss) from discontinued operations, net of tax $ 296 $ (292) 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 $183 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 were reclassified in 2017 as discontinued operations. Summarized results of discontinued operations were as follows: Year Ended December 31, (In millions) 2019 2018 Interest income - affiliate $ — $ 3 Income/(loss) from discontinued operations, net of tax — 3 Settlement consideration, insurance and services credit — 63 Pension and post-retirement liability assumption — 21 Other (3) (53) (Loss)/income on disposal of discontinued operations, net of tax (3) 31 (Loss)/income from discontinued operations, net of tax $ (3) $ 34 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. As a result of GenOn's emergence from bankruptcy, NRG took 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; such letters of credit were never drawn and were returned and canceled on December 17, 2019 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. Dispositions On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MWs of fossil generating assets from its East and West regions of operations for total proceeds of $760 million, subject to standard purchase price adjustments and certain other indemnifications. As part of the transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill plant in New York City through April 2025. The transaction is expected to close in the fourth quarter of 2021, and is subject to various closing conditions, approvals and consents, including FERC, NYSPSC, and antitrust review under Hart-Scott-Rodino. On November 19, 2020, the Company entered an agreement to sell its 35% ownership in Agua Caliente to Clearway Energy for $202 million. The sale of the solar project closed on February 3, 2021. In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $29 million, as further discussed in Note 11, Asset Impairments . On November 13, 2020, the Company completed the sale of the Home Solar business for cash proceeds of $66 million, resulting in a $2 million loss on the sale. In connection with the sale, the Company extinguished debt of $27 million and recognized a $5 million loss on the extinguishment. 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. The Company entered into a project management agreement in 2018 to manage construction of Canal 3 and substantial completion was reached in June 2019. The Company completed other asset sales for cash proceeds of $15 million and $22 million during the years ended December 31, 2020 and 2019, respectively.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair Value of Financial Instruments For cash and cash equivalents, funds deposited by counterparties, restricted cash, 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, 2020 2019 (In millions) Carrying Amount Fair Value Carrying Amount Fair Value Assets Notes receivable $ 2 $ 2 $ 11 $ 8 Liabilities Long-term debt, including current portion (a) $ 8,781 $ 9,446 $ 5,956 $ 6,504 (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, 2020 and 2019: As of December 31, 2020 As of December 31, 2019 (In millions) Level 2 Level 3 Level 2 Level 3 Long-term debt, including current portion $ 9,446 $ — $ 6,388 $ 116 Fair Value Accounting under ASC 820 ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments. • Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forward contracts. • Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models. In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. Recurring Fair Value Measurements Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value. The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy: As of December 31, 2020 Fair Value (In millions) Total Level 1 Level 2 Level 3 Investments in securities (classified within other current and non-current assets) $ 25 $ 10 $ 15 $ — Nuclear trust fund investments: Cash and cash equivalents 23 23 — — U.S. government and federal agency obligations 70 69 1 — Federal agency mortgage-backed securities 89 — 89 — Commercial mortgage-backed securities 36 — 36 — Corporate debt securities 144 — 144 — Equity securities 434 434 — — Foreign government fixed income securities 7 1 6 — Other trust fund investments: U.S. government and federal agency obligations 1 1 — — Derivative assets: Commodity contracts 821 59 623 139 Measured using net asset value practical expedient: Equity securities-nuclear trust fund investments 87 — — — Equity securities 8 — — — Total assets $ 1,745 $ 597 $ 914 $ 139 Derivative liabilities: Commodity contracts $ 884 $ 86 $ 643 $ 155 Total liabilities $ 884 $ 86 $ 643 $ 155 As of December 31, 2019 Fair Value (In millions) Total Level 1 Level 2 Level 3 Investments in securities (classified within other current or non-current assets) $ 20 $ — $ 20 $ — Nuclear trust fund investments: Cash and cash equivalents 17 17 — — U.S. government and federal agency obligations 68 68 — — Federal agency mortgage-backed securities 100 — 100 — Commercial mortgage-backed securities 29 — 29 — Corporate debt securities 109 — 109 — Equity securities 388 388 — — Foreign government fixed income securities 5 — 5 — Other trust fund investments: U.S. government and federal agency obligations 1 1 — — Derivative assets: Commodity contracts 1,170 84 893 193 Measured using net asset value practical expedient: Equity securities-nuclear trust fund investments 78 — — — Equity securities 8 — — — Total assets $ 1,993 $ 558 $ 1,156 $ 193 Derivative liabilities: Commodity contracts $ 1,103 $ 143 $ 805 $ 155 Total liabilities $ 1,103 $ 143 $ 805 $ 155 The following tables reconcile, for the years ended December 31, 2020 and 2019, 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, 2020 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) (In millions) Derivatives (a) Beginning balance as of January 1, 2020 $ 38 Total (losses) — realized/unrealized included in earnings (44) Purchases (13) Transfers into Level 3 (b) 1 Transfers out of Level 3 (b) 2 Ending balance as of December 31, 2020 $ (16) 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, 2020 $ 9 (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, 2019 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) (In millions) Debt Securities Derivatives (a) Total Beginning balance as of January 1, 2019 $ 19 $ 20 $ 39 Contracts added from acquisitions — (3) $ (3) Total (losses) — realized/unrealized included in earnings — (26) (26) Purchases — 40 40 Sale (19) — (19) Transfers into Level 3 (b) — 2 2 Transfers out of Level 3 (b) — 5 5 Ending balance as of December 31, 2019 $ — $ 38 $ 38 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, 2019 $ — $ 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 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 were 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 measured using net asset value practical expedient. See also Note 7, 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 17% of derivative assets and 18% 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, 2020 the credit reserve resulted in a $2 million increase primarily within cost of operations. As of December 31, 2019 the credit reserve did not result in a significant change in fair value in operations revenue and cost of operations. The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2020, 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, 2020 and 2019: Significant Unobservable Inputs December 31, 2020 Fair Value Input/Range (In millions) Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average Power Contracts $ 111 $ 143 Discounted Cash Flow Forward Market Price (per MWh) $ 10 $ 105 $ 21 FTRs 28 12 Discounted Cash Flow Auction Prices (per MWh) (28) 43 0 $ 139 $ 155 Significant Unobservable Inputs December 31, 2019 Fair Value Input/Range (In millions) Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average Power Contracts $ 151 $ 139 Discounted Cash Flow Forward Market Price (per MWh) $ 8 $ 218 $ 24 FTRs 42 16 Discounted Cash Flow Auction Prices (per MWh) (105) 213 0 $ 193 $ 155 The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2020 and 2019: 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, 2020, the Company recorded $50 million of cash collateral posted and $19 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, 2020, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $210 million and NRG held collateral (cash and letters of credit) against those positions of $14 million, resulting in a net exposure of $204 million. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 54% of the Company's exposure before collateral is expected to roll off by the end of 2022. 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 96 % Financial institutions 4 Total 100 % Category Net Exposure (a) (b) (% of Total) Investment grade 59 % Non-Investment grade/Non-Rated 41 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 $47 million exposure to two wholesale counterparties in excess of 10% of the total net exposure discussed above as of December 31, 2020. 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, primarily 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, 2020, aggregate credit risk exposure managed by NRG to these counterparties was approximately $645 million for the next five 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, 2020, 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 provision for credit losses was $108 million, $95 million, and $85 million for the years ending December 31, 2020, 2019, and 2018, 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 credit losses.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities ASC 815 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. The Company may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the 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, and interest rate swaps. As the Company engages principally in the trading and marketing of its generation assets and retail operations, 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 operations, 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. 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, 2020, 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 2021; and • Other energy derivatives instruments extending through 2029. Also, as of December 31, 2020, 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 2037; • 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 was 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 entered into interest rate swap agreements. As of December 31, 2019, NRG had no interest rate derivative instruments as a result of the early termination of such contracts in connection with the repayment of the 2023 Term Loan Facility during the second quarter of 2019. During the fourth quarter of 2020, NRG entered into $1.6 billion of interest rate hedges associated with anticipated certain financing needs. As of December 31, 2020, the interest rate hedges were settled in connection with the issuance of fixed rate debt, resulting in a gain of $11 million that was recorded as a reduction to interest expense. 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, 2020 and 2019. 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. (In millions) Total Volume Commodity Units December 31, 2020 December 31, 2019 Emissions Short Ton 1 3 Renewables Energy Certificates Certificates 5 1 Coal Short Ton 2 10 Natural Gas MMBtu (286) (181) Power MWh 57 38 Capacity MW/Day (1) (1) 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, 2020 December 31, 2019 December 31, 2020 December 31, 2019 Derivatives Not Designated as Cash Flow or Fair Value Hedges : Commodity contracts current $ 560 $ 860 $ 499 $ 781 Commodity contracts long-term 261 310 385 322 Total Derivatives Not Designated as Cash Flow or Fair Value Hedges $ 821 $ 1,170 $ 884 $ 1,103 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 (In millions) Gross Amounts of Recognized Assets/Liabilities Derivative Instruments Cash Collateral (Held)/Posted Net Amount As of December 31, 2020 Commodity contracts: Derivative assets $ 821 $ (658) $ (5) $ 158 Derivative liabilities (884) 658 — (226) Total commodity contracts $ (63) $ — $ (5) $ (68) Gross Amounts Not Offset in the Statement of Financial Position (In millions) Gross Amounts of Recognized Assets/Liabilities Derivative Instruments Cash Collateral (Held)/Posted Net Amount As of December 31, 2019 Commodity contracts: Derivative assets $ 1,170 $ (909) $ (7) $ 254 Derivative liabilities (1,103) 909 73 (121) Total commodity contracts $ 67 $ — $ 66 $ 133 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, for the year 2018: Interest Rate Contracts (In millions) 2018 Accumulated OCI beginning balance $ (54) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts 8 Mark-to-market of cash flow hedge accounting contracts 21 Sale of NRG Yield and Renewables 25 Accumulated OCI ending balance $ — Amounts reclassified from accumulated OCI into income were recorded in discontinued operations. 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 or fair value 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, (In millions) 2020 2019 2018 Unrealized mark-to-market results Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges $ (55) $ (68) $ (73) Reversal of acquired loss/(gain) positions related to economic hedges 4 6 (10) Net unrealized (losses)/gains on open positions related to economic hedges (68) 42 97 Total unrealized mark-to-market (losses)/gains for economic hedging activities (119) (20) 14 Reversal of previously recognized unrealized (gains) on settled positions related to trading activity (20) (11) (12) Net unrealized gains on open positions related to trading activity 15 31 29 Total unrealized mark-to-market (losses)/gains for trading activity (5) 20 17 Total unrealized (losses)/gains $ (124) $ — $ 31 Year Ended December 31, (In millions) 2020 2019 2018 Unrealized gains/(losses) included in operating revenues $ 90 $ 53 $ (113) Unrealized (losses)/gains included in cost of operations (214) (53) 144 Total impact to statement of operations — energy commodities $ (124) $ — $ 31 Total impact to statement of operations — interest rate contracts $ — $ (38) $ — 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, 2020, the $68 million loss from open economic hedge positions was primarily the result of a decrease in the value of forward positions as a result of decreases in ERCOT power prices and heat rate contraction, partially offset by an increase in value of forward positions as a result of decreases in New York capacity prices. The gains from open economic hedge positions of $42 million and $97 million for the years ended December 31, 2019 and 2018, respectively, were primarily the result of an increase in the value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion. 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 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, 2020 was $26 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 $35 million as of December 31, 2020. If called for by the counterparty, $1 million of additional collateral would be required for all contracts with credit rating contingent features as of December 31, 2020. See Note 5, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.

Nuclear Decommissioning Trust F

Nuclear Decommissioning Trust Fund	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Nuclear Decommissioning Trust Fund	Nuclear Decommissioning Trust Fund NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rates charged to rate payers all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations , or ASC 980, because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment. The following table summarizes the aggregate fair values and unrealized gains and losses for the securities held in the trust funds, as well as information about the contractual maturities of those securities. As of December 31, 2020 As of December 31, 2019 (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 $ 23 $ — $ — — $ 17 $ — $ — — U.S. government and federal agency obligations 70 6 — 10 68 4 — 11 Federal agency mortgage-backed securities 89 4 — 24 100 3 — 24 Commercial mortgage-backed securities 36 2 — 27 29 1 1 24 Corporate debt securities 144 13 — 12 109 6 — 11 Equity securities 521 372 — — 466 324 — — Foreign government fixed income securities 7 1 — 10 5 — — 10 Total $ 890 $ 398 $ — $ 794 $ 338 $ 1 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, (In millions) 2020 2019 2018 Realized gains $ 34 $ 18 $ 17 Realized (losses) (13) (9) (13) Proceeds from sale of securities 439 381 513

Inventory

Inventory	12 Months Ended
	Dec. 31, 2020
Inventory Disclosure [Abstract]
Inventory	Inventory Inventory consisted of: As of December 31, (In millions) 2020 2019 Fuel oil $ 37 $ 73 Coal 73 93 Natural gas 22 21 Spare parts 195 196 Total Inventory $ 327 $ 383

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment The Company's major classes of property, plant, and equipment were as follows: As of December 31, Depreciable (In millions) 2020 2019 Lives Facilities and equipment $ 3,365 $ 3,262 1-40 years Land and improvements 329 324 Nuclear fuel 239 235 5 years Hardware and office equipment and furnishings 453 422 2-10 years Construction in progress 97 102 Total property, plant, and equipment 4,483 4,345 Accumulated depreciation (1,936) (1,752) Net property, plant, and equipment $ 2,547 $ 2,593 The Company recorded long-lived asset impairments during the years ended December 31, 2020 and 2019, as further described in Note 11, Asset Impairments. Depreciation expense of property, plant and equipment recorded during the years ended 2020, 2019 and 2018 was $295 million, $271 million and $356 million, respectively.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Leases	Leases The Company leases generating facilities, land, office and equipment, railcars, and storefront space at retail stores. Operating leases with an initial term greater than twelve months are recognized as right-of-use assets and lease liabilities in the consolidated balance sheets. The Company made an accounting policy election for all asset classes not to recognize right-of-use assets and lease liabilities in the consolidated balance sheets for its short-term leases, which are leases that have a lease term of twelve months or less. The Company recognizes lease expense for all operating leases on a straight-line basis over the lease term. In the future, should another systematic basis become more representative of the pattern in which the lessee expects to consume the remaining economic benefit of the right-of-use asset, the Company will use that basis for lease expense. The Company considers a contract to be or to contain a lease when both of the following conditions apply: 1) an asset is either explicitly or implicitly identified in the contract and 2) the contract conveys to the Company the right to control the use of the identified asset for a period of time. The Company has the right to control the use of the identified asset when the Company has both the right to obtain substantially all the economic benefits from the use of the identified asset and the right to direct how and for what purpose the identified asset is used throughout the period of use. Lease payments are typically fixed and payable on a monthly, quarterly, semi-annual or annual basis. Lease payments under certain agreements may escalate over the lease term either by a fixed percentage or a fixed dollar amount. Certain leases may provide for variable lease payments in the form of payments based on usage, a percentage of sales from the location under lease, or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments. The Company has no leases which contain residual value guarantees provided by the Company as a lessee. The Company’s leases may grant the Company an option to renew a lease for an additional term(s) or to terminate the lease after a certain period. As part of its transition from the guidance contained in ASC 840 to the updated guidance in ASC 842, the Company elected not to use the practical expedient of using hindsight to determine the lease term and in assessing impairment of the right-of-use assets. As permitted by ASC 842, the Company made an accounting policy election for all asset classes not to recognize right-of-use assets and lease liabilities in the consolidated balance sheets for its short-term leases, which are leases that have a lease term of twelve months or less. For the initial measurement of lease liabilities, the discount rate that the Company uses is either the rate implicit in the lease, if known, or its incremental borrowing rate, which is the rate of interest that the Company would have to pay to borrow, on a collateralized basis, over a similar term an amount equal to the payments for the lease. In transition to ASC 842, the Company elected to apply the effective date transition method as of the January 1, 2019 adoption date. In accordance with this method, the Company’s reporting for comparative periods prior to January 1, 2019 presented in the financial statements continues to be in conformity with the guidance in ASC 840. The Company elected the following practical expedients, which allow entities to: • Not reassess whether any contracts that existed prior to the January 1, 2019 implementation date are or contain leases; • Not reassess the lease classification for any leases that commenced prior to the January 1, 2019 implementation date, meaning that all commenced capital leases under ASC 840 will be classified as finance leases under ASC 842 and all commenced operating leases under ASC 840 will be classified as operating leases under ASC 842; • Not reassess initial direct costs for any leases; • Not reassess whether existing land easements, which were not previously accounted as leases under ASC 840, are or contain leases; and • Not separate lease and non-lease components for all asset classes, except office space leases and generation facilities leases. As described in Note 4, Acquisitions, Discontinued Operations and Dispositions , upon the close of the South Central Portfolio sale in 2019, the Company entered into an agreement to leaseback the Cottonwood facility through May 2025. The lease was accounted for in accordance with ASC 842-40, Sale and Leaseback Transactions , as an operating lease and accordingly, a right-of-use asset and lease liability were established on the lease commencement date and will be amortized through the end of the lease. Lease Cost: (In millions) For the Year Ended December 31, 2020 For the Year Ended December 31, 2019 Finance lease cost $ 3 $ — Operating lease cost 100 109 Short-term lease cost 3 3 Variable lease cost 6 6 Sublease income (17) (17) Total lease cost $ 95 $ 101 Other information: (In millions) For the Year Ended December 31, 2020 For the Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 101 $ 104 Financing cash flows from finance leases 1 — Right-of-use assets obtained in exchange for new finance lease liabilities 5 — Right-of-use assets obtained in exchange for new operating lease liabilities 4 215 Lease Term and Discount Rate for leases: December 31, 2020 December 31, 2019 Finance leases: Weighted average remaining lease term (in years) 1.1 — Weighted average discount rate 4.79 % — Operating leases: Weighted average remaining lease term (in years) 5.3 7.8 Weighted average discount rate 5.63 % 5.72 % As of December 31, 2020, annual payments based on the maturities of NRG's leases are expected to be as follows: (In millions) 2021 $ 86 2022 82 2023 81 2024 71 2025 47 Thereafter 34 Total undiscounted lease payments $ 401 Less: present value adjustment (54) Total discounted lease payments $ 347

Asset Impairments

Asset Impairments	12 Months Ended
	Dec. 31, 2020
Asset Impairment Charges [Abstract]
Asset Impairments	Asset Impairments 2020 Impairment Losses During the fourth quarter of 2020, the Company completed its annual budget and revised its view of long-term power and fuel prices and the corresponding impact on estimated cash flows associated with its long-lives assets. The Cottonwood facility had estimated cash flows that were lower than its carrying amount and the assets were considered impaired. The fair value of the assets was determined using an income approach by applying a discounted cash flow methodology to the long-term budget for the facility. The income approach utilized estimates of after-tax cash flows, which were Level 3 fair value measurements, and included key inputs such as forecasted power prices, fuel costs, operating and maintenance costs, plant investment capital expenditures and discount rates. The Cottonwood facility is being leased through 2025 and the Company recognized an impairment loss of $32 million in 2020 in the West/Other segment associated with the Company's long-term services agreement and related lease payments, as the carrying amounts of the assets from the contract were higher than the estimated operating cash flow though the remaining lease period. The Company also recorded the following impairments in 2020 based on specific triggering events that occurred: Home Solar — In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $29 million in the West/Other segment to adjust the carrying amount of the assets and liabilities to fair market value based on indicative sale prices. Petra Nova Parish Holdings — During the first quarter of 2020, due to the decline in oil prices, NRG determined that the carrying amount of the Company’s equity method investment exceeded the fair value of the investment and that the decline is considered to be other-than-temporary. In determining the fair value, the Company utilized an income approach to estimate future project cash flows. The Company recorded an impairment loss of $18 million in the Texas segment, which included the anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover certain project debt reserve requirements. Other Impairments — For the year ended December 31, 2020, the Company recorded $14 million of impairment losses related to intangible assets in the Texas segment. 2019 Impairment Losses Petra Nova Parish Holdings — During the third quarter of 2019, NRG contributed $95 million in cash to Petra Nova and posted a $12 million letter of credit to cover certain project debt reserve requirements. The cash portion of the contribution was used by Petra Nova to prepay a significant portion of the project debt. As a result, the previously disclosed guarantee of up to $124 million related to the project level debt provided by NRG was canceled and the remaining project debt became non-recourse to NRG. In relation to this contribution, the Company evaluated the project for impairment and determined that the carrying amount of the Company’s equity method investment exceeded the fair value of the investment and that the decline is considered to be other-than-temporary. In determining the fair value, the Company utilized an income approach and considered project specific assumptions for the estimated future project cash flows. 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 $101 million. Other Impairments — For the year ended December 31, 2019, the Company recorded $12 million of impairment losses primarily related to investments and intangibles. 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 $13 million and impairment losses on equity method investments of $15 million.

Goodwill and Other Intangibles

Goodwill and Other Intangibles	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangibles	Goodwill and Other Intangibles Goodwill NRG's goodwill balance was $579 million as of December 31, 2020 and 2019. As of December 31, 2020, goodwill consisted of $165 million associated with the acquisition of Midwest Generation and $414 million for retail operations acquisitions, including Stream Energy and XOOM, which were acquired in 2019 and 2018, respectively. Intangible Assets The Company's intangible assets as of December 31, 2020, primarily reflect intangible assets established with the acquisitions of various companies, including Stream Energy, XOOM, other retail acquisitions, and Texas Genco. Intangible assets are comprised of the following: • Emission Allowances — These intangibles primarily consist of SO2 emission allowances, including those established with the 2006 acquisition of Texas Genco, RGGI emission credits and California carbon allowances. These emission allowances are held-for-use and are amortized to cost of operations based on units of production. • In-market nuclear fuel contracts — These intangibles were established with the Texas Genco acquisition in 2006 and are amortized to cost of operations over expected volumes over the life of each contract. • Customer 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 marketing vendors and loyalty and affinity partners for customer acquisition. 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. • Other — Consists of renewable energy credits, costs to extend the operating license for STP Units 1 and 2, and energy supply contracts acquired with Stream Energy that represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers. Renewable energy credits are retired, as required, for the applicable compliance period. They are expensed to cost of operations based on NRG’s customer usage. Energy supply contracts are amortized to depreciation and amortization based on the expected delivery under the respective contracts. The following tables summarize the components of NRG's intangible assets subject to amortization: (In millions) Year Ended December 31, 2020 Emission Allowances Fuel Contracts Customer Relationships Marketing Partnerships Trade Names Other (b) Total January 1, 2020 $ 662 $ 49 $ 573 $ 285 $ 373 $ 109 $ 2,051 Purchases 25 — — — — 45 70 Acquisition of businesses (a) — — 22 — — — 22 Retirements — — — — — (35) (35) Write-off of fully amortized balances (4) — (70) — — — (74) Impairment (14) — — — — — (14) Other 3 — 2 — — — 5 December 31, 2020 672 49 527 285 373 119 2,025 Less accumulated amortization (563) (46) (349) (99) (247) (53) (1,357) Net carrying amount $ 109 $ 3 $ 178 $ 186 $ 126 $ 66 $ 668 (a) The weighted average life of acquired intangibles was 5 years for customer relationships (b) RECs are not subject to amortization and had a carrying value of $28 million (In millions) Year Ended December 31, 2019 Emission Allowances Fuel Contracts Customer Relationships Marketing Partnerships Trade Names Other (b) Total January 1, 2019 $ 659 $ 49 $ 478 $ 131 $ 345 $ 80 $ 1,742 Purchases 13 — — — — 29 42 Acquisition of businesses (a) — — 110 154 28 26 318 Usage/Retirements (4) — — — — (17) (21) Write-off of fully amortized balances (8) — (13) — — (9) (30) Impairment — — (2) — — — (2) Other 2 — — — — — 2 December 31, 2019 662 49 573 285 373 109 2,051 Less accumulated amortization (539) (45) (345) (75) (220) (38) (1,262) Net carrying amount $ 123 $ 4 $ 228 $ 210 $ 153 $ 71 $ 789 (a) The weighted average life of acquired intangibles was: customer relationships 7 years, trade names 12 years, marketing partnerships 9 years, and energy supply contracts 2 years (b) RECs are not subject to amortization and had a carrying value of $18 million The following table presents NRG's amortization and retirements of intangible assets for each of the past three years: Years Ended December 31, (In millions) 2020 2019 2018 Emission allowances $ 28 $ 32 $ 39 Customer relationships 74 44 32 Marketing partnerships 24 15 9 Trade names 27 25 23 Other (a) 51 35 30 Total amortization $ 204 $ 151 $ 133 (a) For the years ended December 31, 2020, 2019 and 2018, RECs were retired to cost of operations for $36 million, $17 million and $28 million, respectively. For the years ended December 31, 2020, 2019 and 2018, other intangibles were amortized to depreciation and amortization expense for $15 million, $18 million and $2 million, respectively. The following table presents estimated amortization of NRG's intangible assets as of December 31, 2020 for each of the next five years: (In millions) Year Ended December 31, Emission Allowances Fuel Contracts Customer Relationships Marketing Partnerships Trade Names Other Total 2021 $ 31 $ — $ 64 $ 24 $ 27 $ 3 $ 149 2022 30 1 44 23 27 3 128 2023 30 — 45 23 26 3 127 2024 31 1 16 23 17 3 91 2025 29 — 5 22 11 3 70 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, 2020 and 2019, the value of emission allowances held-for-sale was $14 million and $6 million, respectively, within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.

Receivables Securitization and

Receivables Securitization and Repurchase Facility	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Receivable Securitization and Repurchase Facility	Receivables Securitization and Repurchase Facility Receivables Securitization On September 22, 2020, NRG Receivables LLC, a bankruptcy remote, special purpose, indirect wholly owned subsidiary, entered into the Receivables Facility for an amount up to $750 million, subject to adjustments on a seasonal basis, with issuers of asset-backed commercial paper and commercial banks (the "Lenders".) The assets of NRG Receivables LLC are first available to satisfy the claims of the Lenders before making payments on the subordinated note and equity issued by NRG Receivables LLC. The assets of NRG Receivables LLC are not available to the Company and its subsidiaries or creditors unless and until distributed by NRG Receivables LLC. Under the Receivables Facility, certain indirect subsidiaries of the Company sell their accounts receivables to NRG Receivables LLC, subject to certain terms and conditions. In turn, NRG Receivables LLC grants a security interest in the purchased receivables to the Lenders as collateral for cash borrowings and issuances of letters of credit. Pursuant to the Performance Guaranty, the Company has guaranteed, for the benefit of NRG Receivables and the lenders, the payment and performance by each indirect subsidiary of its respective obligations under the Receivables Facility. The accounts receivables remain on the Company's consolidated balance sheet and any amounts funded by the Lenders to NRG Receivables LLC will be reflected as short-term borrowings. Cash flows from the Receivables Facility are reflected as financing activities in the Company's consolidated statements of cash flows. The Company will continue to service the accounts receivables sold in exchange for a servicing fee. The Receivables Facility is scheduled to expire on September 21, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. Borrowings by NRG Receivables LLC under the Receivables Facility bear interest as defined under the Receivables Financing Agreement. The weighted average interest rate related to usage under the Securitization Facility as of December 31, 2020 was 0.537%. As of December 31, 2020, there were no outstanding borrowings and there were $198 million in letters of credit issued under the Receivables Facility. Repurchase Facility On September 22, 2020, the Company entered into an uncommitted repurchase facility (“Repurchase Facility”) related to the Receivables Facility. Under the Repurchase Facility, the Company can borrow up to $75 million, collateralized by a Long-term Debt and Finance Leases Long-term debt and finance leases consisted of the following: (In millions, except rates) December 31, 2020 December 31, 2019 Interest rate % Recourse debt: Senior Notes, due 2026 $ 1,000 $ 1,000 7.250 Senior Notes, due 2027 1,230 1,230 6.625 Senior Notes, due 2028 821 821 5.750 Senior Notes, due 2029 733 733 5.250 Senior Notes, due 2029 500 — 3.375 Senior Notes, due 2031 1,030 — 3.625 Convertible Senior Notes, due 2048 (a) 575 575 2.750 Senior Secured First Lien Notes, due 2024 600 600 3.750 Senior Secured First Lien Notes, due 2025 500 — 2.000 Senior Secured First Lien Notes, due 2027 900 — 2.450 Senior Secured First Lien Notes, due 2029 500 500 4.450 Revolving Credit Facility — 83 L+ 1.75 Tax-exempt bonds 466 466 1.250 - 4.75 Subtotal recourse debt 8,855 6,008 Non-recourse debt: Other — 34 various Subtotal all non-recourse debt — 34 Subtotal long-term debt (including current maturities) 8,855 6,042 Finance leases 4 — various Subtotal long-term debt and finance leases (including current maturities) 8,859 6,042 Less current maturities (1) (88) Less debt issuance costs (93) (65) Discounts (74) (86) Total long-term debt and finance leases $ 8,691 $ 5,803 (a) The effective interest rate was 5.19% and 5.05% for the years ended December 31, 2020 and 2019, respectively. As of the ex-dividend date of January 29, 2021, the Convertible Notes were convertible at a price of $45.94, which is equivalent to a conversion rate of approximately 21.77 shares of common stock per $1,000 principal amount. The remaining period over which the discount on the liability component will be amortized is 4.7 years. Debt includes the following discounts: As of December 31, (In millions) 2020 2019 Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029 $ (2) $ (1) Convertible Senior Notes, due 2048 (72) (85) Total discounts $ (74) $ (86) Consolidated Annual Maturities As of December 31, 2020, annual payments based on the maturities of NRG's debt and finance leases are expected to be as follows: (In millions) 2021 $ 1 2022 2 2023 1 2024 600 2025 500 Thereafter 7,755 Total $ 8,859 Recourse Debt Senior Notes Issuance of 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes On December 2, 2020, NRG issued $500 million aggregate principal amount of 3.375% senior notes due 2029 (the “2029 Unsecured Notes”) and $1.0 billion aggregate principal amount of 3.625% senior notes due 2031 (the “2031 Unsecured Notes” and, together with the 2029 Unsecured Notes, the “Unsecured Notes”). Interest is payable on the Unsecured Notes on February 15 and August 15 of each year beginning on August 15, 2021 until the maturity date of February 15, 2029 for the 2029 Unsecured Notes and February 15, 2031 for the 2031 Unsecured Notes. Issuance of 2025 and 2027 Senior Secured First Lien Notes On December 2, 2020, NRG issued $1.4 billion of aggregate principal amount of senior secured first lien notes, consisting of $500 million 2.000% senior secured first lien notes due 2025 (the “2025 Secured Notes”) and $900 million 2.450% senior secured first lien notes due 2027 (the “2027 Secured Notes” and, together with the 2025 Secured Notes, the “2025 and 2027 Senior Secured First Lien Notes”), at a discount. The 2027 Secured Notes were issued under NRG’s Sustainability-Linked Bond Framework, which sets out certain sustainability targets, including reducing greenhouse gas emissions. Failure to meet such sustainability targets will result in a 25 basis point increase to the interest rate payable on the 2027 Secured Notes from and including the interest period ending on June 2, 2026. The 2025 and 2027 Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The 2025 and 2027 Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the 2025 and 2027 Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade. Interest is payable on the 2025 and 2027 Senior Secured First Lien Notes on June 2 and December 2 of each year beginning on June 2, 2021 until the maturity date of December 2, 2025 for the 2025 Secured Notes and until the maturity date of December 2, 2027 for the 2027 Secured Notes. Issuance of 2029 Senior Notes On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029, or the 2029 Senior Notes. The 2029 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity date of June 15, 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining 6.25% Senior Notes due 2024. Issuance of 2024 and 2029 Senior Secured First Lien Notes On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 2.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Senior Secured First Lien Notes, at a discount. The Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity dates of June 15, 2024 and June 15, 2029. The proceeds from the issuance of the Senior Secured First Lien Notes, together with cash on hand, were used to repay the Company's 2023 Term Loan Facility. 2019 Senior Note Redemptions During the year ended December 31, 2019, the Company redeemed $733 million of its 6.25% Senior Notes due 2024 and recorded a loss on debt extinguishment of $29 million, which included the write-off of previously deferred debt issuance costs of $5 million. 2048 Convertible Senior Notes 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 Convertible Notes are convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at a price of $46.24 per common share as of December 31, 2020, which is equivalent to an conversion rate of approximately 21.6242 shares of common stock per $1,000 principal amount of Convertible Notes. As of December 31, 2019, the Convertible Notes were convertible at a price of $47.74 per common share, which is equivalent to an conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of Convertible Notes. The carrying amounts of the liability components as of December 31, 2020 and 2019 of $503 million and $491 million, respectively, were calculated by estimating the fair value of similar liabilities without a conversion feature at inception and amortizing the debt discount using the effective interest rate over the life of the note. Senior Notes Early Redemption As of December 31, 2020, NRG had the following outstanding issuances of senior notes with an early redemption feature, or Senior Notes: i. 7.250% senior notes, issued May 23, 2016 and due May 15, 2026, or the 2026 Senior Notes; ii. 6.625% senior notes, issued August 2, 2016 and due January 15, 2027, or the 2027 Senior Notes; iii. 5.750% senior notes, issued December 7, 2017 and due January 15, 2028, or the 2028 Senior Notes; iv. 5.250% senior notes, issued May 24, 2019 and due June 15, 2029, or the 2029 Senior Notes; v. 3.375% senior notes, issued December 2, 2020 and due February 15, 2029, or the 3.375% 2029 Senior Notes; and vi. 3.625% senior notes, issued December 2, 2020 and Due February 15, 2031, or the 2031 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. 2026 Senior Notes 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 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, 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 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 July 15, 2021 to July 14, 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 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 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 % 5.250% 2029 Senior Notes At any time prior to June 15, 2022, NRG may redeem up to 40% of the aggregate principal amount of the 2029 Senior Notes, at a redemption price equal to 105.250% 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, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to June 15, 2024, NRG may redeem all or a part of the 2029 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 102.625% of the note, plus interest payments due on the note through June 15, 2024 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after June 15, 2024, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage June 15, 2024 to June 14, 2025 102.625 % June 15, 2025 to June 14, 2026 101.750 % June 15, 2026 to June 14, 2027 100.875 % June 15, 2027 and thereafter 100.000 % 3.375% 2029 Senior Notes At any time prior to February 15, 2024, NRG may redeem up to 40% of the aggregate principal amount of the 2029 Senior Notes, at a redemption price equal to 103.375% 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, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15, 2024, NRG may redeem all or a part of the 2029 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 101.688% of the note, plus interest payments due on the note through February 15, 2024 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after February 15, 2024, 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 February 15, 2024 to February 14, 2025 101.688 % February 15, 2025 to February 14, 2026 100.844 % February 15, 2026 and thereafter 100.000 % 2031 Senior Notes At any time prior to February 15, 2026, NRG may redeem up to 40% of the aggregate principal amount of the 2031 Senior Notes, at a redemption price equal to 103.625% 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, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15, 2026, NRG may redeem all or a part of the 2031 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 101.813% of the note, plus interest payments due on the note through February 15, 2026 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after February 15, 2026, 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 February 15, 2026 to February 14, 2027 101.813 % February 15, 2027 to February 14, 2028 101.208 % February 15, 2028 to February 14, 2029 100.604 % February 15, 2029 and thereafter 100.000 % Senior Credit Facility 2023 Term Loan Facility Repayment On May 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior First Lien Notes, as well as cash on hand, resulting in a decrease of $594 million to long-term debt outstanding. The Company recorded a loss on debt extinguishment of $17 million, which included the write-off of previously deferred debt issuance costs of $13 million. As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $25 million that was recorded as a reduction to interest expense. Revolving Credit Facility Modification On May 28, 2019, the Company amended its existing credit agreement to, among other thing, (i) provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion, (ii) extend the maturity date of the revolving loans and commitments under the amended credit agreement to May 28, 2024, (iii) provide for a release of the collateral securing the amended credit agreement if NRG obtains an investment grade rating form two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw NRG's investment grade rating or downgrade NRG's rating below investment grade, (iv) reduce the applicable margins for borrowings under (a) ABR Revolving Loans from 1.25% to 0.75% and (b) Eurodollar Revolving Loans from 2.25% to 1.75%, (v) add a sustainability covenant and (vi) make certain other changes to the existing covenants. On August 20, 2020, the Company amended its existing credit agreement to, among other things, (i) increase the existing revolving commitments in an aggregate amount of $802 million, (ii) provide for a new tranche of revolving commitments in an aggregate amount of $273 million with a maturity date that is 30 months after the Acquisition Close Date. The maturity date of the new revolving tranche of commitments may, upon request by the Company, at the option of each applicable lender under the new tranche be extended by a further 12 months, but not beyond May 28, 2024, which is the maturity date of the existing and increased commitments. Other than with respect to the maturity date, the terms of all revolving commitments and loan made pursuant thereto are identical. The increase in the existing commitments, and the commitments with respect to the new tranche, are effective on August 20, 2020 but only became available on the Acquisition Closing Date. For further discussion on the acquisition of Direct Energy see Note 4, Acquisitions, Discontinued Operations and Dispositions . Upon the Acquisition Closing Date, total revolving commitments available, subject to usage, under this amendment will be $3.7 billion. In addition, the amendment includes changes to, among other things, (i) permit the borrowing of up to full amount of the revolving commitments in Canadian dollars, (ii) increase the swingline facility from $50 million to $100 million and provide a $10 million swingline facility in Canadian dollars, (iii) increase the credit facilities lien basket from the greater of $6 billion and 30% of total assets to the greater of $10 billion and 30% of total assets, (iv) increase the credit facilities debt basket from $6 billion to $10 billion, (v) increase the basket for securitization indebtedness from $750 million to $1.7 billion, (vi) provide an additional indebtedness basket equal to $600 million for certain liquidity facilities, and (vii) make certain other changes to the existing covenants and other provisions. Tax Exempt Bonds As of December 31, (In millions, except rates) 2020 2019 Interest Rate % NRG Indian River Power 2020, tax exempt bonds, due 2040 $ 57 $ — 1.250 NRG Indian River Power 2020, tax exempt bonds, due 2045 190 — 1.250 Indian River Power, tax exempt bonds, due 2040 — 57 6.000 Indian River Power LLC, tax exempt bonds, due 2045 — 190 5.375 NRG Dunkirk 2020, tax exempt bonds, due 2042 59 — 1.300 Dunkirk Power LLC, tax exempt bonds, due 2042 — 59 5.875 City of Texas City, tax exempt bonds, due 2045 33 33 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 $ 466 Dunkirk Bonds On March 11, 2020, NRG issued $59 million in aggregate principal amount of NRG Dunkirk 2020 1.30% tax-exempt refinancing bonds due 2042 (the "Dunkirk Bonds"). The Dunkirk Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Dunkirk Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Dunkirk Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The Dunkirk Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042. NRG used the net proceeds from the offering to redeem during 2020 the existing principal amount of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042. Indian River Bonds On December 17, 2020, NRG issued $57 million in aggregate principal amount of NRG Indian River 2020 1.25% tax-exempt refinancing bonds due 2040 (the "IR 2040 Bonds") and $190 million aggregate principal amount of NRG Indian River Power 2020 1.25% tax-exempt refinancing bonds due 2045 (the "IR 2045 Bonds") (together the "IR Bonds"). The IR Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The IR Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the IR Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the IR Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The IR Bonds are subject to mandatory tender and purchase on October 1, 2025 and have final maturity dates of October 1, 2040 for the IR 2040 Bonds and October 1, 2045 for the IR 2045 Bonds. NRG used the net proceeds from the offering to redeem during 2020 the existing principal amounts of outstanding Indian River Power 6.000% tax exempt bonds due 2040 and Indian River Power LLC 5.375% tax exempt bonds due 2045. Non-Recourse Debt The following are descriptions of certain indebtedness of NRG's subsidiaries. All of NRG's non-recourse debt is secured by the assets in the respective project subsidiaries as further described below. Credit Default Swap Facility On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease. Annual fees of 1.33% on the facility were paid quarterly in advance. On August 13, 2020, the agreement was amended permitting the Company to increase the size of the facility and fees on the facility were adjusted to reflect the costs of the credit default swaps that serve as collateral for the facility. In order to increase the Company’s collective collateral facilities in connection with the Direct Energy acquisition, NRG expanded the facility allowing for the issuance of an additional $150 million of letters of credit as of December 31, 2020. As of December 31, 2020, $229 million was issued under this facility. Bilateral Letter of Credit Facilities In December 2020 the Company entered into a series of Bilateral Letter of Credit Facilities to allow for the issuance of up to $475 million of letters of credit. These facilities are uncommitted. As of December 31, 2020, $5 million was issued under these facilities. Put Option Agreement for Senior Debt Issuance During the fourth quarter of 2020, the Company entered into a 3-year put option agreement with a Delaware trust formed by the Company upon completion of the sale of $900 million pre-capitalized trust securities redeemable November 15, 2023 (the “P-Caps”). The Trust invested the proceeds from the sale of the P-Caps in a portfolio of principal and interest strips of U.S. Treasury securities (the “Eligible Treasury Assets”). Under the put option agreement, NRG has the right, from time to time, to issue to the Trust and to require the Trust to purchase from NRG, on one or more occasions (the “Issuance Right”), up to $900 million aggregate principal amount of NRG’s 1.841% Senior Secured First Lien Notes due 2023 (the “P-Caps Secured Notes”) in exchange for all or a portion of the Eligible Treasury Assets corresponding to the portion of the Issuance Right. NRG will pay a semi-annual premium to the Trust at a rate of 1.65%. The P-Caps are to be redeemed by the Trust on November 15, 2023 or earlier upon an early redemption of the P-Caps Secured Notes. Following any distribution of P-Caps Secured Notes to the holders of the P-Caps, NRG may similarly redeem such P-Caps Secured Notes, in whole or in part, at the redemption price described below, plus accrued but unpaid interest to, but excluding, the date of redemption. Any P-Caps Secured Notes outstanding and held by the Trust as a result of the exercise of the Issuance Right that remain outstanding will also mature on November 15, 2023. The Issuance Right will be exercised automatically in full if (1) NRG fails to pay the facility fee when due or any amount due and owing under the trust expense reimbursement agreement or fails to purchase and pay for any Eligible Treasury Assets that are due and not paid on their payment date and such failure is not cured within 30 days, or (2) upon certain bankruptcy events of NRG. NRG will be required to mandatorily exercise the Issuance Right if (1) an Acquisition Triggering Event has occurred, (2) NRG’s consolidated stockholders’ equity, determined in accordance with GAAP, but excluding accumulated other comprehensive income (or loss), equity of non-controlling interests attributable thereto and treasury stock at cost, has fallen below $2.0 billion, which amount may be adjusted from time to time upon the occurrence of certain specified events, (3) an event of default under the P-Caps Secured Notes Indenture (as defined below) has occurred or would have occurred had the P-Caps Secured Notes been outstanding, (4) NRG breaches its covenant to maintain sufficient capacity under other material agreements to permit the issuance of the P-Caps Secured Notes in full, (5) a Collateral Enforcemen

Long-term Debt and Finance Leas

Long-term Debt and Finance Leases	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-term Debt and Finance Leases	Receivables Securitization and Repurchase Facility Receivables Securitization On September 22, 2020, NRG Receivables LLC, a bankruptcy remote, special purpose, indirect wholly owned subsidiary, entered into the Receivables Facility for an amount up to $750 million, subject to adjustments on a seasonal basis, with issuers of asset-backed commercial paper and commercial banks (the "Lenders".) The assets of NRG Receivables LLC are first available to satisfy the claims of the Lenders before making payments on the subordinated note and equity issued by NRG Receivables LLC. The assets of NRG Receivables LLC are not available to the Company and its subsidiaries or creditors unless and until distributed by NRG Receivables LLC. Under the Receivables Facility, certain indirect subsidiaries of the Company sell their accounts receivables to NRG Receivables LLC, subject to certain terms and conditions. In turn, NRG Receivables LLC grants a security interest in the purchased receivables to the Lenders as collateral for cash borrowings and issuances of letters of credit. Pursuant to the Performance Guaranty, the Company has guaranteed, for the benefit of NRG Receivables and the lenders, the payment and performance by each indirect subsidiary of its respective obligations under the Receivables Facility. The accounts receivables remain on the Company's consolidated balance sheet and any amounts funded by the Lenders to NRG Receivables LLC will be reflected as short-term borrowings. Cash flows from the Receivables Facility are reflected as financing activities in the Company's consolidated statements of cash flows. The Company will continue to service the accounts receivables sold in exchange for a servicing fee. The Receivables Facility is scheduled to expire on September 21, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. Borrowings by NRG Receivables LLC under the Receivables Facility bear interest as defined under the Receivables Financing Agreement. The weighted average interest rate related to usage under the Securitization Facility as of December 31, 2020 was 0.537%. As of December 31, 2020, there were no outstanding borrowings and there were $198 million in letters of credit issued under the Receivables Facility. Repurchase Facility On September 22, 2020, the Company entered into an uncommitted repurchase facility (“Repurchase Facility”) related to the Receivables Facility. Under the Repurchase Facility, the Company can borrow up to $75 million, collateralized by a Long-term Debt and Finance Leases Long-term debt and finance leases consisted of the following: (In millions, except rates) December 31, 2020 December 31, 2019 Interest rate % Recourse debt: Senior Notes, due 2026 $ 1,000 $ 1,000 7.250 Senior Notes, due 2027 1,230 1,230 6.625 Senior Notes, due 2028 821 821 5.750 Senior Notes, due 2029 733 733 5.250 Senior Notes, due 2029 500 — 3.375 Senior Notes, due 2031 1,030 — 3.625 Convertible Senior Notes, due 2048 (a) 575 575 2.750 Senior Secured First Lien Notes, due 2024 600 600 3.750 Senior Secured First Lien Notes, due 2025 500 — 2.000 Senior Secured First Lien Notes, due 2027 900 — 2.450 Senior Secured First Lien Notes, due 2029 500 500 4.450 Revolving Credit Facility — 83 L+ 1.75 Tax-exempt bonds 466 466 1.250 - 4.75 Subtotal recourse debt 8,855 6,008 Non-recourse debt: Other — 34 various Subtotal all non-recourse debt — 34 Subtotal long-term debt (including current maturities) 8,855 6,042 Finance leases 4 — various Subtotal long-term debt and finance leases (including current maturities) 8,859 6,042 Less current maturities (1) (88) Less debt issuance costs (93) (65) Discounts (74) (86) Total long-term debt and finance leases $ 8,691 $ 5,803 (a) The effective interest rate was 5.19% and 5.05% for the years ended December 31, 2020 and 2019, respectively. As of the ex-dividend date of January 29, 2021, the Convertible Notes were convertible at a price of $45.94, which is equivalent to a conversion rate of approximately 21.77 shares of common stock per $1,000 principal amount. The remaining period over which the discount on the liability component will be amortized is 4.7 years. Debt includes the following discounts: As of December 31, (In millions) 2020 2019 Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029 $ (2) $ (1) Convertible Senior Notes, due 2048 (72) (85) Total discounts $ (74) $ (86) Consolidated Annual Maturities As of December 31, 2020, annual payments based on the maturities of NRG's debt and finance leases are expected to be as follows: (In millions) 2021 $ 1 2022 2 2023 1 2024 600 2025 500 Thereafter 7,755 Total $ 8,859 Recourse Debt Senior Notes Issuance of 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes On December 2, 2020, NRG issued $500 million aggregate principal amount of 3.375% senior notes due 2029 (the “2029 Unsecured Notes”) and $1.0 billion aggregate principal amount of 3.625% senior notes due 2031 (the “2031 Unsecured Notes” and, together with the 2029 Unsecured Notes, the “Unsecured Notes”). Interest is payable on the Unsecured Notes on February 15 and August 15 of each year beginning on August 15, 2021 until the maturity date of February 15, 2029 for the 2029 Unsecured Notes and February 15, 2031 for the 2031 Unsecured Notes. Issuance of 2025 and 2027 Senior Secured First Lien Notes On December 2, 2020, NRG issued $1.4 billion of aggregate principal amount of senior secured first lien notes, consisting of $500 million 2.000% senior secured first lien notes due 2025 (the “2025 Secured Notes”) and $900 million 2.450% senior secured first lien notes due 2027 (the “2027 Secured Notes” and, together with the 2025 Secured Notes, the “2025 and 2027 Senior Secured First Lien Notes”), at a discount. The 2027 Secured Notes were issued under NRG’s Sustainability-Linked Bond Framework, which sets out certain sustainability targets, including reducing greenhouse gas emissions. Failure to meet such sustainability targets will result in a 25 basis point increase to the interest rate payable on the 2027 Secured Notes from and including the interest period ending on June 2, 2026. The 2025 and 2027 Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The 2025 and 2027 Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the 2025 and 2027 Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade. Interest is payable on the 2025 and 2027 Senior Secured First Lien Notes on June 2 and December 2 of each year beginning on June 2, 2021 until the maturity date of December 2, 2025 for the 2025 Secured Notes and until the maturity date of December 2, 2027 for the 2027 Secured Notes. Issuance of 2029 Senior Notes On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029, or the 2029 Senior Notes. The 2029 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity date of June 15, 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining 6.25% Senior Notes due 2024. Issuance of 2024 and 2029 Senior Secured First Lien Notes On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 2.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Senior Secured First Lien Notes, at a discount. The Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity dates of June 15, 2024 and June 15, 2029. The proceeds from the issuance of the Senior Secured First Lien Notes, together with cash on hand, were used to repay the Company's 2023 Term Loan Facility. 2019 Senior Note Redemptions During the year ended December 31, 2019, the Company redeemed $733 million of its 6.25% Senior Notes due 2024 and recorded a loss on debt extinguishment of $29 million, which included the write-off of previously deferred debt issuance costs of $5 million. 2048 Convertible Senior Notes 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 Convertible Notes are convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at a price of $46.24 per common share as of December 31, 2020, which is equivalent to an conversion rate of approximately 21.6242 shares of common stock per $1,000 principal amount of Convertible Notes. As of December 31, 2019, the Convertible Notes were convertible at a price of $47.74 per common share, which is equivalent to an conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of Convertible Notes. The carrying amounts of the liability components as of December 31, 2020 and 2019 of $503 million and $491 million, respectively, were calculated by estimating the fair value of similar liabilities without a conversion feature at inception and amortizing the debt discount using the effective interest rate over the life of the note. Senior Notes Early Redemption As of December 31, 2020, NRG had the following outstanding issuances of senior notes with an early redemption feature, or Senior Notes: i. 7.250% senior notes, issued May 23, 2016 and due May 15, 2026, or the 2026 Senior Notes; ii. 6.625% senior notes, issued August 2, 2016 and due January 15, 2027, or the 2027 Senior Notes; iii. 5.750% senior notes, issued December 7, 2017 and due January 15, 2028, or the 2028 Senior Notes; iv. 5.250% senior notes, issued May 24, 2019 and due June 15, 2029, or the 2029 Senior Notes; v. 3.375% senior notes, issued December 2, 2020 and due February 15, 2029, or the 3.375% 2029 Senior Notes; and vi. 3.625% senior notes, issued December 2, 2020 and Due February 15, 2031, or the 2031 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. 2026 Senior Notes 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 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, 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 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 July 15, 2021 to July 14, 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 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 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 % 5.250% 2029 Senior Notes At any time prior to June 15, 2022, NRG may redeem up to 40% of the aggregate principal amount of the 2029 Senior Notes, at a redemption price equal to 105.250% 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, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to June 15, 2024, NRG may redeem all or a part of the 2029 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 102.625% of the note, plus interest payments due on the note through June 15, 2024 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after June 15, 2024, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage June 15, 2024 to June 14, 2025 102.625 % June 15, 2025 to June 14, 2026 101.750 % June 15, 2026 to June 14, 2027 100.875 % June 15, 2027 and thereafter 100.000 % 3.375% 2029 Senior Notes At any time prior to February 15, 2024, NRG may redeem up to 40% of the aggregate principal amount of the 2029 Senior Notes, at a redemption price equal to 103.375% 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, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15, 2024, NRG may redeem all or a part of the 2029 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 101.688% of the note, plus interest payments due on the note through February 15, 2024 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after February 15, 2024, 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 February 15, 2024 to February 14, 2025 101.688 % February 15, 2025 to February 14, 2026 100.844 % February 15, 2026 and thereafter 100.000 % 2031 Senior Notes At any time prior to February 15, 2026, NRG may redeem up to 40% of the aggregate principal amount of the 2031 Senior Notes, at a redemption price equal to 103.625% 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, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15, 2026, NRG may redeem all or a part of the 2031 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 101.813% of the note, plus interest payments due on the note through February 15, 2026 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after February 15, 2026, 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 February 15, 2026 to February 14, 2027 101.813 % February 15, 2027 to February 14, 2028 101.208 % February 15, 2028 to February 14, 2029 100.604 % February 15, 2029 and thereafter 100.000 % Senior Credit Facility 2023 Term Loan Facility Repayment On May 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior First Lien Notes, as well as cash on hand, resulting in a decrease of $594 million to long-term debt outstanding. The Company recorded a loss on debt extinguishment of $17 million, which included the write-off of previously deferred debt issuance costs of $13 million. As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $25 million that was recorded as a reduction to interest expense. Revolving Credit Facility Modification On May 28, 2019, the Company amended its existing credit agreement to, among other thing, (i) provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion, (ii) extend the maturity date of the revolving loans and commitments under the amended credit agreement to May 28, 2024, (iii) provide for a release of the collateral securing the amended credit agreement if NRG obtains an investment grade rating form two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw NRG's investment grade rating or downgrade NRG's rating below investment grade, (iv) reduce the applicable margins for borrowings under (a) ABR Revolving Loans from 1.25% to 0.75% and (b) Eurodollar Revolving Loans from 2.25% to 1.75%, (v) add a sustainability covenant and (vi) make certain other changes to the existing covenants. On August 20, 2020, the Company amended its existing credit agreement to, among other things, (i) increase the existing revolving commitments in an aggregate amount of $802 million, (ii) provide for a new tranche of revolving commitments in an aggregate amount of $273 million with a maturity date that is 30 months after the Acquisition Close Date. The maturity date of the new revolving tranche of commitments may, upon request by the Company, at the option of each applicable lender under the new tranche be extended by a further 12 months, but not beyond May 28, 2024, which is the maturity date of the existing and increased commitments. Other than with respect to the maturity date, the terms of all revolving commitments and loan made pursuant thereto are identical. The increase in the existing commitments, and the commitments with respect to the new tranche, are effective on August 20, 2020 but only became available on the Acquisition Closing Date. For further discussion on the acquisition of Direct Energy see Note 4, Acquisitions, Discontinued Operations and Dispositions . Upon the Acquisition Closing Date, total revolving commitments available, subject to usage, under this amendment will be $3.7 billion. In addition, the amendment includes changes to, among other things, (i) permit the borrowing of up to full amount of the revolving commitments in Canadian dollars, (ii) increase the swingline facility from $50 million to $100 million and provide a $10 million swingline facility in Canadian dollars, (iii) increase the credit facilities lien basket from the greater of $6 billion and 30% of total assets to the greater of $10 billion and 30% of total assets, (iv) increase the credit facilities debt basket from $6 billion to $10 billion, (v) increase the basket for securitization indebtedness from $750 million to $1.7 billion, (vi) provide an additional indebtedness basket equal to $600 million for certain liquidity facilities, and (vii) make certain other changes to the existing covenants and other provisions. Tax Exempt Bonds As of December 31, (In millions, except rates) 2020 2019 Interest Rate % NRG Indian River Power 2020, tax exempt bonds, due 2040 $ 57 $ — 1.250 NRG Indian River Power 2020, tax exempt bonds, due 2045 190 — 1.250 Indian River Power, tax exempt bonds, due 2040 — 57 6.000 Indian River Power LLC, tax exempt bonds, due 2045 — 190 5.375 NRG Dunkirk 2020, tax exempt bonds, due 2042 59 — 1.300 Dunkirk Power LLC, tax exempt bonds, due 2042 — 59 5.875 City of Texas City, tax exempt bonds, due 2045 33 33 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 $ 466 Dunkirk Bonds On March 11, 2020, NRG issued $59 million in aggregate principal amount of NRG Dunkirk 2020 1.30% tax-exempt refinancing bonds due 2042 (the "Dunkirk Bonds"). The Dunkirk Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Dunkirk Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Dunkirk Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The Dunkirk Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042. NRG used the net proceeds from the offering to redeem during 2020 the existing principal amount of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042. Indian River Bonds On December 17, 2020, NRG issued $57 million in aggregate principal amount of NRG Indian River 2020 1.25% tax-exempt refinancing bonds due 2040 (the "IR 2040 Bonds") and $190 million aggregate principal amount of NRG Indian River Power 2020 1.25% tax-exempt refinancing bonds due 2045 (the "IR 2045 Bonds") (together the "IR Bonds"). The IR Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The IR Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the IR Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the IR Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The IR Bonds are subject to mandatory tender and purchase on October 1, 2025 and have final maturity dates of October 1, 2040 for the IR 2040 Bonds and October 1, 2045 for the IR 2045 Bonds. NRG used the net proceeds from the offering to redeem during 2020 the existing principal amounts of outstanding Indian River Power 6.000% tax exempt bonds due 2040 and Indian River Power LLC 5.375% tax exempt bonds due 2045. Non-Recourse Debt The following are descriptions of certain indebtedness of NRG's subsidiaries. All of NRG's non-recourse debt is secured by the assets in the respective project subsidiaries as further described below. Credit Default Swap Facility On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease. Annual fees of 1.33% on the facility were paid quarterly in advance. On August 13, 2020, the agreement was amended permitting the Company to increase the size of the facility and fees on the facility were adjusted to reflect the costs of the credit default swaps that serve as collateral for the facility. In order to increase the Company’s collective collateral facilities in connection with the Direct Energy acquisition, NRG expanded the facility allowing for the issuance of an additional $150 million of letters of credit as of December 31, 2020. As of December 31, 2020, $229 million was issued under this facility. Bilateral Letter of Credit Facilities In December 2020 the Company entered into a series of Bilateral Letter of Credit Facilities to allow for the issuance of up to $475 million of letters of credit. These facilities are uncommitted. As of December 31, 2020, $5 million was issued under these facilities. Put Option Agreement for Senior Debt Issuance During the fourth quarter of 2020, the Company entered into a 3-year put option agreement with a Delaware trust formed by the Company upon completion of the sale of $900 million pre-capitalized trust securities redeemable November 15, 2023 (the “P-Caps”). The Trust invested the proceeds from the sale of the P-Caps in a portfolio of principal and interest strips of U.S. Treasury securities (the “Eligible Treasury Assets”). Under the put option agreement, NRG has the right, from time to time, to issue to the Trust and to require the Trust to purchase from NRG, on one or more occasions (the “Issuance Right”), up to $900 million aggregate principal amount of NRG’s 1.841% Senior Secured First Lien Notes due 2023 (the “P-Caps Secured Notes”) in exchange for all or a portion of the Eligible Treasury Assets corresponding to the portion of the Issuance Right. NRG will pay a semi-annual premium to the Trust at a rate of 1.65%. The P-Caps are to be redeemed by the Trust on November 15, 2023 or earlier upon an early redemption of the P-Caps Secured Notes. Following any distribution of P-Caps Secured Notes to the holders of the P-Caps, NRG may similarly redeem such P-Caps Secured Notes, in whole or in part, at the redemption price described below, plus accrued but unpaid interest to, but excluding, the date of redemption. Any P-Caps Secured Notes outstanding and held by the Trust as a result of the exercise of the Issuance Right that remain outstanding will also mature on November 15, 2023. The Issuance Right will be exercised automatically in full if (1) NRG fails to pay the facility fee when due or any amount due and owing under the trust expense reimbursement agreement or fails to purchase and pay for any Eligible Treasury Assets that are due and not paid on their payment date and such failure is not cured within 30 days, or (2) upon certain bankruptcy events of NRG. NRG will be required to mandatorily exercise the Issuance Right if (1) an Acquisition Triggering Event has occurred, (2) NRG’s consolidated stockholders’ equity, determined in accordance with GAAP, but excluding accumulated other comprehensive income (or loss), equity of non-controlling interests attributable thereto and treasury stock at cost, has fallen below $2.0 billion, which amount may be adjusted from time to time upon the occurrence of certain specified events, (3) an event of default under the P-Caps Secured Notes Indenture (as defined below) has occurred or would have occurred had the P-Caps Secured Notes been outstanding, (4) NRG breaches its covenant to maintain sufficient capacity under other material agreements to permit the issuance of the P-Caps Secured Notes in full, (5) a Collateral Enforcemen

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company's AROs are primarily related to the environmental obligations for nuclear decommissioning, mine reclamation, ash disposal, site closures, 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 7, 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 . The following table represents the balance of ARO obligations as of December 31, 2020 and 2019, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2020: (In millions) Nuclear Decommission Other (a) Total Balance as of December 31, 2019 $ 298 $ 430 $ 728 Revisions in estimates for current obligations (12) 38 26 Additions — 3 3 Spending for current obligations — (43) (43) Accretion 17 29 46 Balance as of December 31, 2020 $ 303 $ 457 $ 760 (a) Total accretion expense related to asset retirement obligations included in the consolidated statement of cash flows includes accretion and revisions in estimates for asset retirement liabilities on non-operating plants

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Benefit Plans and Other Postretirement Benefits	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. Participation in the NRG Pension Plan for Bargained Employees depends upon whether an employee is covered by a bargaining agreement. NRG expects to contribute $30 million to the Company's pension plans in 2021, of which $14 million relates to the GenOn plan. 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 (In millions) 2020 2019 2018 Service cost benefits earned $ 10 $ 10 $ 23 Interest cost on benefit obligation 38 46 44 Expected return on plan assets (61) (59) (62) Amortization of unrecognized net loss 5 3 — Settlement/curtailment expense — — 7 Net periodic benefit (credit)/cost $ (8) $ — $ 12 Year Ended December 31, Other Postretirement Benefits (In millions) 2020 2019 2018 Service cost benefits earned $ — $ 1 $ 1 Interest cost on benefit obligation 3 3 4 Amortization of unrecognized prior service cost (14) (13) (10) Amortization of unrecognized net loss 1 — — Curtailment gain — — (10) Net periodic benefit credit $ (10) $ (9) $ (15) 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 (In millions) 2020 2019 2020 2019 Benefit obligation at January 1 $ 1,397 $ 1,222 $ 93 $ 83 Service cost 10 10 — 1 Interest cost 38 46 3 3 Plan amendments — — — (2) Actuarial loss 126 207 — 16 Employee and retiree contributions — — 3 4 Benefit payments (82) (88) (9) (12) Benefit obligation at December 31 1,489 1,397 90 93 Fair value of plan assets at January 1 1,150 981 — — Actual return on plan assets 193 216 — — Employee and retiree contributions — — 3 4 Employer contributions 11 41 6 7 Benefit payments (82) (88) (9) (11) Fair value of plan assets at December 31 1,272 1,150 — — Funded status at December 31 — excess of obligation over assets $ (217) $ (247) $ (90) $ (93) During the year ended December 31, 2020, the actuarial loss of $126 million on pension benefits was driven by decreasing discount rates and demographic assumptions, partially offset by gains from life expectancy projection updates. During the year ended December 31, 2019, the actuarial loss of $207 million on pension benefits was driven by decreasing discount rates, assumption changes to reflect current market conditions and actual experience different than assumed, partially offset by gains from life expectancy projection updates. Amounts recognized in NRG's balance sheets were as follows: As of December 31, Pension Benefits Other Postretirement Benefits (In millions) 2020 2019 2020 2019 Other current liabilities $ — $ — $ 5 $ 7 Other non-current liabilities 217 247 85 86 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 (In millions) 2020 2019 2020 2019 Net loss $ 127 $ 138 $ 6 $ 7 Prior service cost/(credit) 2 2 (29) (43) Total accumulated OCI $ 129 $ 140 $ (23) $ (36) Other changes in plan assets and benefit obligations recognized in OCI were as follows: Year Ended December 31, Pension Benefits Other Postretirement Benefits (In millions) 2020 2019 2020 2019 Net actuarial (gain)/loss $ (6) $ 50 $ — $ 16 Amortization of net actuarial (gain) (5) (3) (1) — Prior service credit — — — (2) Amortization of prior service cost — — 14 12 Total recognized in OCI $ (11) $ 47 $ 13 $ 26 Net periodic benefit credit (8) — (10) (9) Net recognized in net periodic pension credit and OCI $ (19) $ 47 $ 3 $ 17 The following table presents the balances of significant components of NRG's pension plan: As of December 31, Pension Benefits (In millions) 2020 2019 Projected benefit obligation $ 1,489 $ 1,397 Accumulated benefit obligation 1,455 1,362 Fair value of plan assets 1,272 1,150 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, 2020 (In millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total Common/collective trust investment — U.S. equity $ — $ 284 $ 284 Common/collective trust investment — non-U.S. equity — 113 113 Common/collective trust investment — non-core assets — 151 151 Common/collective trust investment — fixed income — 258 258 Short-term investment fund 13 — 13 Subtotal fair value $ 13 $ 806 $ 819 Measured at net asset value practical expedient: Common/collective trust investment — non-U.S. equity 45 Common/collective trust investment — fixed income 289 Common/collective trust investment — non-core assets 84 Partnerships/joint ventures 35 Total fair value $ 1,272 Fair Value Measurements as of December 31, 2019 (In millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total Common/collective trust investment — U.S. equity $ — $ 233 $ 233 Common/collective trust investment — non-U.S. equity — 73 73 Common/collective trust investment — non-core assets — 143 143 Common/collective trust investment — fixed income — 272 272 Short-term investment fund 12 — 12 Subtotal fair value $ 12 $ 721 $ 733 Measured at net asset value practical expedient: Common/collective trust investment — non-U.S. equity 84 Common/collective trust investment — fixed income 279 Common/collective trust investment — non-core assets 24 Partnerships/joint ventures 30 Total fair value $ 1,150 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 2020 2019 2020 2019 Discount rate 2.56 % 3.26 % 2.54 % 3.26 % Interest crediting rate 3.12 % — 1.62 % — Rate of compensation increase 3.00 % 3.00 % — % — % Health care trend rate — — 7.2% grading to 4.5% in 2028 7.5% grading to 4.5% in 2028 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 2020 2019 2018 2020 2019 2018 Discount rate 3.26 % 4.38%/4.20% 3.71%/4.04% 3.26% 4.37% 3.71% /4.08% Interest crediting rate 3.66 % — — 2.28 % — — Expected return on plan assets 5.93 % 6.35 % 6.17 % — — — Rate of compensation increase 3.00 % 3.00 % 3.00 % — — — Health care trend rate — — — 7.5% grading to 4.5% in 2028 7.8% grading to 4.5% in 2025 8.2% grading to 4.5% 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. The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2020: U.S. equity 20 % Non-U.S. equity 13 % Non-core assets 17 % U.S. fixed income 50 % 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 Short, Intermediate and Long Credits/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 (In millions) Pension Benefit Payments Benefit Payments Medicare Prescription Drug Reimbursements 2021 $ 90 $ 6 $ — 2022 89 6 — 2023 87 5 — 2024 85 5 — 2025 83 5 — 2026-2030 386 19 2 STP Defined Benefit Plans NRG has a 44% undivided ownership interest in STP, as discussed further in Note 29, 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. During the third quarter of 2019, STPNOC announced that the defined benefit pension plan will be frozen for non-union employees on December 31, 2021, This resulted in the curtailment of benefits, thereby requiring a remeasurement, including an update to the discount rate used to determine benefit obligations. As a result, during 2019, NRG recognized a gain of $8 million related to the curtailment of benefits and an increase of $32 million to the pension liability was recorded to other comprehensive income. The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. For the years ended December 31, 2020 and December 31, 2019, NRG reimbursed STPNOC $8 million and $24 million, respectively, for its contribution to the plans. In 2021, NRG expects to reimburse STPNOC $18 million for its contribution to the plan. 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 (In millions) 2020 2019 2020 2019 Funded status — STPNOC benefit plans $ (99) $ (77) $ (20) $ (20) Net periodic benefit cost/(credit) 7 9 (4) (4) Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss) 22 (13) 5 6 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, (In millions) 2020 2019 2018 Company contributions to defined contribution plans $ 22 $ 22 $ 28

Capital Structure

Capital Structure	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Capital Structure	Capital Structure For the period from December 31, 2017 to December 31, 2020, 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, 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 Shares issued under ESPP — 46,128 46,128 Shares issued under LTIPs 1,601,904 — 1,601,904 Share repurchases — (36,301,882) (36,301,882) Balance as of December 31, 2019 421,890,790 (172,894,601) 248,996,189 Shares issued under ESPP — 131,469 131,469 Shares issued under LTIPs 1,167,058 — 1,167,058 Share repurchases — (6,062,783) (6,062,783) Balance as of December 31, 2020 423,057,848 (178,825,915) 244,231,933 Common Stock As of December 31, 2020, NRG had 14,862,069 shares of common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of the long-term incentive plans. Common stock dividends — The Company declared and paid $0.30, $0.03 and $0.03 quarterly dividend per common share, or $1.20, $0.12 and $0.12 per share on an annualized basis for 2020, 2019 and 2018 respectively. In the first quarter of 2020, NRG increased the annual dividend to $1.20 from $0.12 per share, as part of a long-term capital allocation policy adopted in the fourth quarter of 2019, that targets allocating 50% of cash available for allocation generated each year to growth investments and 50% to be returned to shareholders. The return of capital to shareholders is expected to be completed through the increased dividend supplemented by share repurchases. The long-term capital allocation policy targets an annual dividend growth rate of 7-9% per share in years subsequent to 2020. In 2021 NRG increased the annual dividend to $1.30 per share, representing an 8% increase. The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations. On January 21, 2021, NRG declared a quarterly dividend on the Company's common stock of $0.325 per share, or $1.30 per share on an annualized basis, payable on February 16, 2021, to stockholders of record as of February 1, 2021. Employee Stock Purchase Plan — In March 2019, the Company reopened participation in the ESPP, which allows eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of NRG common stock at the lesser of 95% of its market value on the offering date or 95% of the fair market value on the exercise date. An offering date will occur each April 1 and October 1. An exercise date will occur each September 30 and March 31. The ESPP, that was suspended in 2018, allowed eligible employees to 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 occurred each January 1 and July 1. An exercise date occurred each June 30 and December 31. As of December 31, 2020, there remained 2,753,591 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. The Company executed $1.25 billion of these share repurchases in 2018, with the remaining $0.25 billion completed in the first quarter of 2019. In 2019, the Company's board of directors authorized the Company to repurchase an additional $1.25 billion of its common stock. The Company executed $1.194 billion of these share repurchases in 2019 and completed the remaining $56 million under the 2019 authorization by February 27, 2020. The remaining repurchases in 2020 were made under the long-term capital allocation policy discussed above. The following table summarizes the shares repurchases made during the years 2018, 2019 and 2020: Total number of shares and share equivalents purchased Average price paid per share and share equivalent Amounts paid for shares and share equivalents purchased (in millions) 2018 repurchases: 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 Other repurchases 11,097,631 396 Total Share Repurchases during 2018 35,234,664 $ 35.48 $ 1,250 2019 repurchases: Repurchases under February 28, 2019 Accelerated Share Repurchase Agreement 9,438,671 400 Other repurchases 26,863,211 1,008 Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (a) 936,928 36 Total Share Repurchases during 2019 37,238,810 $ 38.79 $ 1,444 2020 repurchases: Repurchases 6,062,783 197 Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (a) 711,248 27 Total Share Repurchases during 2020 6,774,031 $ 33.05 $ 224 (a) NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management. The average price per equivalent shares withheld was $38.23 and $38.78 in 2020 and 2019, respectively. See Note 22, Stock-Based Compensation, for further discussion of the equity awards

Investments Accounted for by th

Investments Accounted for by the Equity Method and Variable Interest Entities	12 Months Ended
	Dec. 31, 2020
Equity Method Investments and Joint Ventures [Abstract]
Investments Accounted for by the Equity Method and Variable Interest Entities	Investments Accounted for by the Equity Method and Variable Interest Entities Entities that are not Consolidated NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by 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, 2020: (In millions, except percentages) Name Economic Investment Balance (a) Agua Caliente 35.0 % $ 185 Gladstone 37.5 % 131 Ivanpah Master Holdings, LLC 54.5 % 17 Watson Cogeneration Company 49.0 % 14 Midway-Sunset Cogeneration Company 50.0 % 12 Petra Nova Parish Holdings, LLC (b) 50.0 % (13) Total equity investments in affiliates $ 346 (a) As of December 31, 2020, the carry value of NRG's equity method investment was $343 million lower than the underlying net assets of the investees. The basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets. The basis difference is primarily due to impairments booked on Petra Nova, but not booked at the project level, as well as differences related to the deconsolidations of Ivanpah and Agua Caliente in 2018 and the treatment of certain deferred tax assets. (b) Refer to Note 11, Asset Impairments , for discussion of NRG's investment in Petra Nova Parish Holdings, LLC As of December 31, (In millions) 2020 2019 Undistributed earnings from equity investments $ 30 $ 42 PG&E Bankruptcy — The Agua Caliente project and two of the three Ivanpah units 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 primary operating subsidiary utility PG&E filed for Chapter 11 relief in the California Bankruptcy Court. As a result of the bankruptcy filing, Agua Caliente and the two Ivanpah units were issued notices of events of default under their respective loan agreements. On September 9, 2019, PG&E filed a plan of reorganization that would assume all power purchase agreements, including those held by Agua Caliente and the two Ivanpah units. The California Bankruptcy Court approved the PG&E plan and the Confirmation Order was entered on June 19, 2020. The plan went effective, and PG&E emerged from bankruptcy on July 1, 2020. In July 2020, the U.S. DOE agreed to waivers of the bankruptcy-related events of default with respect to the Agua Caliente and Ivanpah projects. Subsequent to PG&E's emergence from bankruptcy, the Agua Caliente and the Ivanpah projects were allowed to resume distributions, and as of December 31, 2020, NRG received $50 million. In November 2020, Clearway Energy Inc. agreed to buy NRG’s 35% interest in Agua Caliente. The transaction closed on February 3, 2021. 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 $131 million as of December 31, 2020. 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 related to the Receivables Facility, as further described in Note 13, Receivables Securitization and Repurchase Facility, and 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 . During the first quarter of 2020, the Company repurchased its partners' equity interest in one of the remaining partnerships. As the Company retains control of its interest in the entity, the repurchase was recorded to equity. During the fourth quarter of 2020, the Company completed the sale of its other remaining tax equity arrangement, as part of the sale of the Home Solar business for $66 million. The summarized financial information for the Company's consolidated VIEs consisted of the following: (In millions) December 31, 2020 December 31, 2019 Accounts receivable $ 647 $ 3 Other current assets 2 — Net property, plant and equipment — 71 Other long-term assets — 27 Total assets 649 101 Current liabilities 78 4 Long-term debt — 24 Other long-term liabilities — 8 Total liabilities 78 36 Redeemable noncontrolling interests — 20 Net assets less noncontrolling interests $ 571 $ 45

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic income per common share is computed by dividing net income 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 per share is computed in a manner consistent with that of basic income 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 and relative performance stock units are not considered outstanding for purposes of computing basic income per share. However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method. The 2048 Convertible Senior Notes are convertible, under certain circumstances, into the Company’s common stock, cash or combination thereof (at NRG's option). There is no dilutive effect for the 2048 Convertible Senior Notes due to the Company’s expectation to settle the liability in cash. 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, (In millions, except per share amounts) 2020 2019 2018 Basic income per share attributable to NRG, Inc; Net income attributable to NRG Energy, Inc. common stockholders $ 510 $ 4,438 $ 268 Weighted average number of common shares outstanding-basic 245 262 304 Income per weighted average common share — basic $ 2.08 $ 16.94 $ 0.88 Diluted income per share attributable to NRG, Inc; Net income attributable to NRG Energy, Inc. common stockholders $ 510 $ 4,438 $ 268 Weighted average number of common shares outstanding-basic 245 262 304 Incremental shares attributable to the issuance of equity compensation (treasury stock method) 1 2 4 Weighted average number of common shares outstanding-diluted 246 264 308 Income per weighted average common share — diluted $ 2.07 $ 16.81 $ 0.87 As of December 31, 2020 and 2019 and 2018 the Company had an insignificant number of outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted income per share.

Segment Reporting

Segment Reporting	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting The Company began managing its integrated model based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments to Texas, East and West/Other beginning in the first quarter of 2020. The Company's updated segment structure reflects how management makes financial decisions and allocates resources. All affected disclosures presented herein have been recast to reflect these changes for all periods presented. For further discussion, refer to Note 1, Nature of Busines s. 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. In February 2019, the Company completed the sale and deconsolidation of the South Central Portfolio and Carlsbad. On August 31, 2018, NRG deconsolidated NRG Yield Inc., its Renewables Platform and Carlsbad for financial reporting purposes. In 2018, the financial information for historical periods was recast to reflect the presentation of discontinued operations within the corporate segment. Refer to Note 4, Acquisitions, Discontinued Operations and Dispositions , for further discussion. The Company had no customer that comprised more than 10% of the Company's consolidated revenues during the years ended December 31, 2020 and 2019. The company had one customer in the Texas segment that comprised 11% of the Company's consolidated revenues during the year ended December 31, 2018. Intersegment sales are accounted for at market. For the Year Ended December 31, 2020 (In millions) Texas East West/Other Corporate (a) Eliminations Total Operating revenues (a) $ 6,309 $ 2,354 $ 434 $ — $ (4) $ 9,093 Operating expenses 5,246 1,828 346 57 (4) 7,473 Depreciation and amortization 227 142 32 34 — 435 Impairment losses 14 — 61 — — 75 Development costs 4 3 1 — — 8 Total operating cost and expenses 5,491 1,973 440 91 (4) 7,991 (Loss)/gain on sale of assets — — (2) 5 — 3 Operating income/(loss) 818 381 (8) (86) — 1,105 Equity in (losses)/earnings of unconsolidated affiliates (12) — 29 — — 17 Impairment losses on investments (18) — — — — (18) Other income, net 11 7 8 41 — 67 Loss on debt extinguishment — (4) (5) — — (9) Interest expense — (14) (3) (384) — (401) Income/(loss) from continuing operations before income taxes 799 370 21 (429) — 761 Income tax (benefit)/expense — (1) 2 250 — 251 Net income/(loss) attributable to NRG Energy, Inc. $ 799 $ 371 $ 19 $ (679) $ — $ 510 Balance sheet Equity investments in affiliates $ (13) $ — $ 359 $ — $ — $ 346 Capital expenditures 130 45 30 25 — 230 Goodwill (b) 325 254 — — — 579 Total assets $ 7,641 $ 1,885 $ 1,584 $ 11,152 $ (7,360) $ 14,902 (a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues $ 6 $ (6) $ 4 $ — $ — $ 4 (b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach For the Year Ended December 31, 2019 (In millions) Texas East West/Other Corporate (a) Eliminations Total Operating revenues (a) $ 7,069 $ 2,319 $ 440 $ — $ (7) $ 9,821 Operating expenses 5,818 1,895 397 50 (7) 8,153 Depreciation and amortization 188 121 33 31 — 373 Impairment losses 1 — 4 — — 5 Development costs 3 3 1 — — 7 Total operating cost and expenses 6,010 2,019 435 81 (7) 8,538 Gain on sale of assets — 1 — 6 — 7 Operating income/(loss) 1,059 301 5 (75) — 1,290 Equity in (losses)/earnings of unconsolidated affiliates (4) — 6 — — 2 Impairment losses on investments (103) — — (5) — (108) Other income, net 20 6 10 30 — 66 Loss on debt extinguishment — — (3) (48) — (51) Interest expense — (18) (10) (385) — (413) Income/(loss) from continuing operations before income taxes 972 289 8 (483) — 786 Income tax expense/(benefit) — 2 1 (3,337) — (3,334) Net income from continuing operations 972 287 7 2,854 — 4,120 Gain from discontinued operations, net of income tax — — — 321 — 321 Net Income 972 287 7 3,175 — 4,441 Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests — — 3 — — 3 Net income attributable to NRG Energy, Inc. $ 972 $ 287 $ 4 $ 3,175 $ — $ 4,438 Balance sheet Equity investments in affiliates $ 6 $ — $ 382 $ — $ — $ 388 Capital expenditures 136 30 25 37 — 228 Goodwill (b) 325 254 — — — 579 Total assets $ 5,711 $ 2,160 $ 1,190 $ 8,342 $ (4,872) $ 12,531 (a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues $ 1 $ 8 $ (2) $ — $ — $ 7 (b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach For the Year Ended December 31, 2018 (In millions) Texas East West/Other Corporate (a) Eliminations Total Operating revenues (a) $ 6,401 $ 2,371 $ 724 $ — $ (18) $ 9,478 Operating expenses 5,399 2,024 467 125 (18) 7,997 Depreciation and amortization 156 105 127 33 — 421 Impairment losses 5 82 12 — — 99 Development costs 3 3 3 2 — 11 Total operating cost and expenses 5,563 2,214 609 160 (18) 8,528 Gain/(loss) on sale of assets 4 — (2) 30 — 32 Operating income/(loss) 842 157 113 (130) — 982 Equity in (losses)/earnings of unconsolidated affiliates (3) — 13 (1) — 9 Impairment losses on investments (15) — — — — (15) Other income/(loss), net 13 2 4 (1) — 18 Loss on debt extinguishment — — — (44) — (44) Interest expense — (22) (39) (422) — (483) Income/(loss) from continuing operations before income taxes 837 137 91 (598) — 467 Income tax expense — 1 — 6 — 7 Net income/(loss) from continuing operations 837 136 91 (604) — 460 Loss from discontinued operations, net of income tax — — — (192) — (192) Net Income/(loss) 837 136 91 (796) — 268 Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests — — 5 (5) — — Net income/(loss) attributable to NRG Energy, Inc. $ 837 $ 136 $ 86 $ (791) $ — $ 268 (a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues $ 19 $ (5) $ 4 $ — $ — $ 18 (b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The income tax provision from continuing operations consisted of the following amounts: Year Ended December 31, (In millions, except effective income tax rate) 2020 2019 2018 Current State $ 22 $ 2 $ 6 Foreign 4 4 — Total — current 26 6 6 Deferred U.S. Federal 168 (3,000) (16) State 60 (340) 16 Foreign (3) — 1 Total — deferred 225 (3,340) 1 Total income tax expense/(benefit) $ 251 $ (3,334) $ 7 Effective income tax rate 33.0 % (424.2) % 1.5 % During the year ended December 31, 2019, NRG released the majority of its valuation allowance against its U.S. federal and state deferred tax assets, resulting in a non-cash benefit to income tax expense of approximately $3.5 billion. In making the determination to release the majority of the valuation allowance as of December 31, 2019, the Company evaluated a number of factors, including its recent history of pre-tax earnings, utilization of $593 million of NOLs in 2019, as well as its forecasted future pre-tax earnings. Based on this evaluation, the Company determined that the majority of its future tax benefits are more-likely-than-not to be realized. Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the Company expects to generate income before taxes in the U.S. in future periods at a level that would fully utilize its U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration. On March 27, 2020, the Senate passed the CARES Act to provide emergency relief related to the COVID-19 pandemic. The CARES Act contains federal income tax provisions which, among other things: (i) increases the amount of interest expense that businesses are allowed to deduct by increasing the adjusted taxable income limitation from 30% to 50% for tax years that begin in 2019 and 2020; (ii) permits businesses to carry back to each of the five tax years NOLs arising from tax years beginning after December 31, 2017 and before January 1, 2020; and (iii) temporarily removes the 80% limitation on NOLs until tax years beginning after 2020. The CARES Act provisions did not have a material impact on the tax positions of the Company. The following represented the domestic and foreign components of income from continuing operations before income taxes: Year Ended December 31, (In millions) 2020 2019 2018 U.S. $ 749 $ 771 $ 468 Foreign 12 15 (1) Total $ 761 $ 786 $ 467 Reconciliations of the U.S. federal statutory tax rate to NRG's effective tax rate were as follows: Year Ended December 31, (In millions, except effective income tax rate) 2020 2019 2018 Income from continuing operations before income taxes $ 761 $ 786 $ 467 Tax at federal statutory tax rate 160 165 98 State taxes 18 13 18 Permanent differences 8 (9) 7 Changes in valuation allowance 24 (3,492) (106) Deferred impact of state tax rate changes 2 12 — Production tax credits ("PTC") — — (7) Recognition of uncertain tax benefits 3 (10) 1 Return to provision adjustments 36 — — Alternative minimum tax ("AMT") refundable credit — — (4) Other — (13) — Income tax expense/(benefit) $ 251 $ (3,334) $ 7 Effective income tax rate 33.0 % (424.2) % 1.5 % For the year ended December 31, 2020, NRG's effective income tax rate was higher than the federal statutory tax rate of 21% primarily due to state tax expense, the recognition of state valuation allowance on NOLs, and return to provision adjustments. For the year ended December 31, 2019, NRG's effective income tax rate was lower than the federal statutory tax rate of 21% primarily due to the tax benefit from the release of the valuation allowance. For the year ended December 31, 2018, NRG's effective income tax rate was lower 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. The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following: As of December 31, (In millions) 2020 2019 Deferred tax assets: Deferred compensation, accrued vacation and other reserves $ 79 $ 81 Difference between book and tax basis of property 357 548 Pension and other postretirement benefits 86 86 Equity compensation 10 11 Bad debt reserve 16 13 Derivatives, net 11 — U.S. Federal net operating loss carryforwards 2,117 2,116 Foreign net operating loss carryforwards 102 105 State net operating loss carryforwards 351 360 Federal and state tax credit carryforwards 384 384 Federal benefit on state uncertain tax positions 4 4 Interest disallowance carryforward per §163(j) of the Tax Act 4 82 Inventory obsolescence 6 7 Other 10 3 Total deferred tax assets 3,537 3,800 Deferred tax liabilities: Emissions allowances 21 19 Derivatives, net — 27 Goodwill 29 8 Intangibles amortization (excluding goodwill) 2 15 Equity method investments 156 201 Convertible Debt 16 19 Total deferred tax liabilities 224 289 Total deferred tax assets less deferred tax liabilities 3,313 3,511 Valuation allowance (266) (242) Total net deferred tax assets, net of valuation allowance $ 3,047 $ 3,269 The following table summarizes NRG's net deferred tax position as presented in the consolidated balance sheets: As of December 31, (In millions) 2020 2019 Deferred tax asset $ 3,066 $ 3,286 Deferred tax liability (19) (17) Net deferred tax asset $ 3,047 $ 3,269 The primary drivers for the decrease in the net deferred tax asset from $3.3 billion as of December 31, 2019 to $3.0 billion as of December 31, 2020 are a decrease in the tax basis of property and the utilization of previously disallowed interest, partially offset by a change in equity method investments. Deferred tax assets and valuation allowance Net deferred tax balance — As of December 31, 2020 and 2019, NRG recorded a net deferred tax asset, excluding valuation allowance, of $3.3 billion and $3.5 billion, respectively. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of December 31, 2020 as discussed below. NOL carryforwards — As of December 31, 2020, the Company had tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $2.1 billion and $351 million, respectively. The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before the expiration of certain carryforwards commences in 2031. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $102 million with no expiration date. Valuation allowance — As of December 31, 2020, the Company's tax-effected valuation allowance was $266 million, consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary differences. Taxes Receivable and Payable As of December 31, 2020, NRG recorded a current tax payable of $12 million that represents a tax liability due for state income taxes that is primarily comprised of Texas margin tax. 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 with after-tax value of $15 million as of December 31, 2020 and 2019, for which NRG has recorded a non-current tax liability of $18 million and $17 million, respectively. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. The Company recognized expense of $1 million related to interest in each of the years ended December 31, 2020, 2019 and 2018. As of December 31, 2020 and 2019, NRG had cumulative interest and penalties related to these uncertain tax benefits of $3 million and $2 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 and Canada. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2017. With few exceptions, state and local income tax examinations are no longer open for years before 2012. The following table summarizes uncertain tax benefits activity: As of December 31, (In millions) 2020 2019 Balance as of January 1 $ 15 $ 26 Increase due to current year positions 3 2 Settlements, payments and statute closure (3) (13) Uncertain tax benefits as of December 31 $ 15 $ 15

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement, Noncash Expense [Abstract]
Stock-Based Compensation	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, 2020 and 2019, a total of 25,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP. There were 9,385,730 and 9,935,750 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 2020 and 2019, 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, 2020 and 2019, there were 78,903 and 319,264 shares of common stock remaining available for grants under the NRG GenOn LTIP, respectively. Restricted Stock Units As of December 31, 2020, RSUs granted under the Company's LTIPs typically have three Units Weighted Average Grant Date Fair Value per Unit Non-vested at December 31, 2019 717,239 $ 25.56 Granted 271,718 38.05 Forfeited (16,750) 35.86 Vested (452,693) 20.73 Non-vested at December 31, 2020 519,514 35.87 The total fair value of RSUs vested during the years ended December 31, 2020, 2019 and 2018 was $17 million, $36 million and $42 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2020, 2019 and 2018 was $38.05, $37.37 and $28.90, respectively. Deferred Stock Units DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established under the terms of the award. DSUs granted under the Company's LTIPs are fully vested at the date of issuance. Fair value of the DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in the period of grant. The following table summarizes the Company's outstanding DSU awards and changes during the year: Units Weighted Average Grant Date Fair Value per Unit Outstanding at December 31, 2019 331,223 $ 23.98 Granted 58,861 35.59 Converted to Common Stock (47,378) 26.87 Outstanding at December 31, 2020 342,706 25.37 The aggregate intrinsic values for DSUs outstanding as of December 31, 2020, 2019 and 2018 were approximately $13 million each year. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2020, 2019 and 2018 were $2 million, $2 million and $6 million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2020, 2019 and 2018 was $35.59, $34.84 and $33.43, 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. PSUs include RPSUs and MSUs. As of December 31, 2020, non-vested PSUs consist primarily of 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 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 was 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. As of March 1, 2021 all MSUs were vested. The following table summarizes the Company's non-vested PSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit Non-vested at December 31, 2019 1,200,541 $ 26.65 Granted (a) 928,215 23.75 Forfeited (5,142) 35.77 Vested (b) (1,330,053) 15.91 Non-vested at December 31, 2020 (c) 793,561 41.69 (a) The weighted average grant date fair value per unit includes RPSUs that were granted during 2020 with grant date fair value of $45.60. It also includes RPSUs with 2017 grant date fair value of $15.91 and MSUs with 2016 grant date fair value of $15.28, that due to vesting at 200%, were considered additional grants in 2020 (b) MSUs granted during 2016 and RPSUs granted during 2017 vested during 2020 at 200% (c) Non-vested units as of December 31, 2020 includes 4,260 MSUs which were vested as of March 1, 2021 The weighted average grant date fair value of PSUs granted during the years ended December 31, 2020, 2019 and 2018, was $23.75, $22.50 and $35.36, 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: 2020 2019 2018 2017 2016 RPSUs RPSUs RPSUs RPSUs MSUs Expected volatility 30.15 % 40.72 % 47.52 % 43.96 % 34.33 % Expected term (in years) 3 3 3 3 3 Risk free rate 1.58 % 2.45 % 2.01 % 1.5 % 1.31 % For the years ended December 31, 2020 and 2019, 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. Non-Qualified Stock Options All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2020, 2019 and 2018. No NQSOs were granted in 2020, 2019 or 2018. NRG recognized compensation costs for NQSOs over the requisite service period for the entire award. No compensation expense was recognized during 2020, 2019 or 2018 as it was fully recognized in prior years. The maximum contractual term is 10 years for NRG's outstanding NQSOs. The following table summarizes the Company's NQSO activity and changes during the year: Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in millions) Outstanding at December 31, 2019 134,398 $ 25.31 1 $ 2 Expired (9,083) 37.44 Exercised (48,268) 23.33 Outstanding at December 31, 2020 77,047 25.13 0.5 1 Exercisable at December 31, 2020 77,047 25.13 0.5 1 The following table summarizes the total intrinsic value of options exercised and the cash received from the exercises of options: Year Ended December 31, (In millions) 2020 2019 2018 Total intrinsic value of options exercised $ 1 $ 2 $ 10 Cash received from options exercised 1 3 24 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, 2020, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $27 million, $36 million, and $19 million for the years ended December 31, 2020, 2019, and 2018, respectively, are reflected as a reduction to additional paid-in capital on the Company's consolidated balance sheets. Non-vested Compensation Cost (In millions, except weighted average data) Compensation Expense Unrecognized Total Cost Weighted Average Recognition Period Remaining (In years) Year Ended December 31, As of December 31, Award 2020 2019 2018 2020 2020 RSUs $ 9 $ 9 $ 12 $ 7 1.15 DSUs 2 2 2 — 0.00 MSUs — — 4 — 0.01 RPSUs 10 10 7 10 0.95 PRSUs (a) 6 11 16 6 1.24 Total $ 27 $ 32 $ 41 $ 23 Tax detriment recognized $ (9) $ (12) $ (4) three

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions NRG provides services to some of its equity method investments under operations and maintenance agreements. Fees for the services under these agreements include recovery of NRG's costs of operating the plants. Certain agreements also include fees for administrative service, a base monthly fee, profit margin and/or annual incentive bonus. The following table summarizes NRG's material related party transactions with third party affiliates: Year Ended December 31, (In millions) 2020 2019 2018 Revenues from Related Parties Included in Operating Revenues Gladstone $ 4 $ 4 $ 3 GenConn (a) — — 4 Ivanpah (b) 43 35 20 Midway-Sunset 5 5 5 Total $ 52 $ 44 $ 32 (a) As of August 31, 2018, NRG no longer had an ownership interest in GenConn as a result of the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform (b) Includes fees under project management agreements with each project company. Ivanpah became a related party to NRG upon deconsolidation in the second quarter of 2018 Services Agreement and Transition Services Agreement with GenOn

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies 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. As of December 31, 2020, the Company's minimum commitments under such outstanding agreements are estimated as follows: Period (In millions) 2021 $ 146 2022 98 2023 69 2024 67 2025 65 Thereafter 80 Total (a) $ 525 (a) Actual coal, gas and transportation purchases are significantly higher than these estimated minimum unconditional long-term firm commitments For the years ended December 31, 2020, 2019 and 2018, the Company purchased $0.8 billion, $1.2 billion and $1.2 billion, respectively, under coal, gas and transportation arrangements. Purchased Power Commitments NRG has purchased power contracts of various quantities and durations, including renewable purchased power agreements under PPAs with third-party project developers, which are accounted for as NPNS. These contracts are not included in the consolidated balance sheet as of December 31, 2020. Minimum purchase commitment obligations are as follows as of December 31, 2020: Period (In millions) 2021 $ 48 2022 62 2023 50 2024 50 2025 49 Thereafter 316 Total (a) $ 575 (a) Actual power purchases are significantly higher than these estimated minimum unconditional long-term firm commitments For the years ended December 31, 2020, 2019 and 2018, the Company purchased $142 million, $183 million and $138 million, respectively, under purchased power arrangements. First Lien Structure NRG has granted first liens to certain counterparties on a substantial portion of property and assets owned by NRG and the guarantors of its senior debt. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedges. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a claim under the first lien program. As of December 31, 2020, hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis. Nuclear Insurance STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Act. The current liability limit per incident is $13.8 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 adjustment expected to be effective no later than November 1, 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 $13.3 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, per reactor. In addition, the U.S. Congress retains the ability to impose additional financial requirements on the nuclear industry to pay liability claims that exceed $13.8 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 $2.8 billion in limits for nuclear events and $1.0 billion in limits for non-nuclear events. The nuclear event limit remains the maximum available from NEIL. The upper $1.3 billion in nuclear events limits (excess of the first $1.5 billion in nuclear events 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 primary 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 $2 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. Accidental Outage coverage amounts decrease in the event more than one unit at a station is out of service due to a common accident. 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 ensure 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 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 accruals 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 accrual for the applicable legal matters, including regulatory and environmental matters as further discussed in Note 25, Regulatory Matters , and Note 26, Environmental Matters . 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 accruals 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. 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 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 sought damages for the alleged improper charges and a declaration as to which charges were proper under the contract. In February 2020, the court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. On March 17, 2020, plaintiffs filed a lawsuit in the Nineteenth Judicial District Court for the Parish of East Baton Rouge in Louisiana alleging substantially the same matters. 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. Sierra club et al. v. Midwest Generation LLC — In 2012, several environmental groups filed a complaint against Midwest Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in groundwater contamination. In June 2019, the IPCB found that Midwest Generation violated the law because it had improperly handled coal ash at four facilities in Illinois and caused or allowed coal ash constituents to impact groundwater. On September 9, 2019, Midwest Generation filed a Motion to Reconsider numerous issues, which the court granted in part and denied in part on February 6, 2020. The IPCB will hold hearings to determine the appropriate relief. Midwest Generation has been working with the Illinois EPA to address the groundwater issues since 2010. XOOM Energy Litigation — XOOM has been a defendant in two purported class action lawsuits in Maryland and New York. The plaintiffs generally claim that they did not receive the savings they were promised in their natural gas and electricity bills. In the Maryland lawsuit, the district court denied plaintiff's' bid to certify the case as a class action on August 18, 2020. The matter has been dismissed. In the New York case, XOOM filed a motion to dismiss, which the court granted on September 21, 2018, later entering judgment in XOOM's favor on September 24, 2018. The plaintiffs in the New York case appealed to the U.S. Court of Appeals for the Second Circuit. On July 26, 2019, the Second Circuit reversed the judgment of the district court and remanded to the district court with instructions that plaintiffs be permitted to proceed on their proposed amended complaint. The New York case is in the discovery phase. This matter was known and accrued for at the time of the acquisition.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2020
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 operations. 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. California Station Power — As the result of unfavorable final and non-appealable litigation, the Company accrued a liability associated with consumption of station power at the Company's Encina power plant facility in California after August 30, 2010. The Company has established an appropriate accrual pending potential regulatory action by SDG&E regarding the Company's Encina facility. South Central — On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO and PJM markets. FERC Office of Enforcement Staff investigated potential violations of MISO rules involving bidding for the Big Cajun 2 facility, as well as other aspects of NRG’s operations in MISO. On August 18, 2020, FERC Office of Enforcement presented NRG with its preliminary findings. NRG responded to the preliminary findings on January 15, 2021. 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. ISO-NE — On January 8, 2021, the Commission approved a settlement agreement the Company entered into to resolve FERC Enforcement Staff's investigation of offers submitted during the qualification period for the ISO-NE Forward Capacity Auction in 2016. The settlement was approved in a 2-1 vote. The Commission Chairman dissented on the basis that the investigation should have been terminated because the Company should not be penalized for reflecting a different expectation from that of the ISO-NE Internal Market Monitor in its forecast of future events submitted for independent review in the tariff-prescribed bid review process. Under the settlement, the Company agreed to pay a civil penalty of $85 thousand and is subject to compliance monitoring.

Environmental Matters

Environmental Matters	12 Months Ended
	Dec. 31, 2020
Environmental Matters Disclosure [Abstract]
Environmental Matters	Environmental Matters Air On July 8, 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO 2 emissions from the power sector. The ACE rule required states that have coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). Accordingly, we expect the EPA to promulgate a new rule to regulate GHG emissions from power plants. Water Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed 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 amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. The Company is in the process of estimating the environmental capital expenditures that will be required to comply. The capital expenditures required to comply will depend on elections regarding future operations of each coal-fired unit. NRG expects to make these elections for each unit in Q4 2021 at which time the EPA will be notified as required. Accordingly, we do not expect to provide estimates of ELG compliance costs until early 2022. 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 September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amended 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. In 2019 and 2020, the EPA proposed several changes to this rule. On August 28, 2020, the EPA finalized "A Holistic Approach to Close Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing impoundments with an alternative liner. The Company has updated its estimates of required environmental capital expenditures.

Cash Flow Information

Cash Flow Information	12 Months Ended
	Dec. 31, 2020
Supplemental Cash Flow Information [Abstract]
Cash Flow Information	Cash Flow Information Detail of supplemental disclosures of cash flow and non-cash investing and financing information was: Year Ended December 31, (In millions) 2020 2019 2018 Interest paid, net of amount capitalized $ 340 $ 372 $ 436 Income taxes paid, net of refunds 24 8 9 Non-cash investing activities: (Decreases)/additions to fixed assets for accrued capital expenditures (6) 1 20

Guarantees

Guarantees	12 Months Ended
	Dec. 31, 2020
Guarantees [Abstract]
Guarantees	Guarantees 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, (In millions) 2020 Guarantees Under 1 Year 1-3 Years 3-5 Years Over 5 Years Total 2019 Total Letters of credit and surety bonds $ 1,049 $ 73 $ 31 $ — $ 1,153 $ 1,024 Asset sales guarantee obligations 86 282 26 112 506 698 Other guarantees — — — 87 87 288 Total guarantees $ 1,135 $ 355 $ 57 $ 199 $ 1,746 $ 2,010 Letters of credit and surety bonds — As of December 31, 2020, NRG and its consolidated subsidiaries were contingently obligated for a total of $1.2 billion under letters of credit and surety bonds. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements and obligations associated with future closure and maintenance of ash sites, as well as for financing or other arrangements. A majority of these letters of credit and surety bonds expire within one 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 for the California property tax indemnity for estimated increases in California property taxes of certain solar properties that the Company agreed to indemnify NRG Yield for, as part of the agreement to sell NRG Yield and the Renewables Platform. The California property tax indemnity is estimated to be $176 million as of December 31, 2020 and is included in the above table under asset sales guarantee obligations. Other guarantees — NRG has issued other guarantees of obligations including payments under certain agreements with respect to certain of its unconsolidated subsidiaries, payment or performance by fuel providers and payment or reimbursement of credit support and deposits. The Company does not believe that it will be required to perform under these guarantees. Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any material payments under these indemnity provisions. Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be able to estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.

Jointly Owned Plants

Jointly Owned Plants	12 Months Ended
	Dec. 31, 2020
Jointly Owned Plants Disclosure [Abstract]
Jointly Owned Plants	Jointly Owned Plants Certain NRG subsidiaries own undivided interests in jointly-owned plants, as described below. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries' share of operating costs and direct expenses and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company's consolidated financial statements. The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities: (In millions unless otherwise stated) As of December 31, 2020 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress South Texas Project Units 1 and 2, Bay City, TX 44.00 % $ 428 $ (227) $ 1 Cedar Bayou Unit 4, Baytown, TX 50.00 % 220 (101) 9

SCHEDULE II - VALUATION AND QUA

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS	12 Months Ended
	Dec. 31, 2020
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS	SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2020, 2019 and 2018 (In millions) Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Deductions Balance at End of Period Allowance for credit losses, deducted from accounts receivable Year Ended December 31, 2020 $ 43 $ 108 $ — $ (84) (a) $ 67 Year Ended December 31, 2019 32 95 — (84) (a) 43 Year Ended December 31, 2018 28 83 — (79) (a) 32 Income tax valuation allowance, deducted from deferred tax assets Year Ended December 31, 2020 $ 242 $ 24 $ — $ — $ 266 Year Ended December 31, 2019 3,794 (3,543) (9) — 242 Year Ended December 31, 2018 1,863 1,934 (128) 125 (b) 3,794 (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

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Segment Reporting	The Company began managing its integrated model based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of 2020. The Company's updated segment structure reflects how management makes financial decisions and allocates resources. The Company's businesses are segregated as follows: • Texas, which includes all activity related to customer, plant and market operations in Texas; • East, which includes the remaining activity related to customer operations and all activity related to plant and market operations in the East; • West/Other, which includes the following assets and activities: (i) all activity related to plant and market operations in the West, (ii) activity related to the Cottonwood power plant that was sold to Cleco on February 4, 2019 and is being leased back until 2025, (iii) the remaining renewables activity, including the Company’s equity method investments in Ivanpah Master Holdings, LLC and Agua Caliente (which was sold on February 3, 2021), the remaining Home Solar assets (which were primarily sold on November 13, 2020) and the NFL stadium solar generating assets, and (iv) activity related to the Company’s equity method investment for the Gladstone power plant in Australia; and • Corporate activities. All affected disclosures presented herein have been recast to reflect these changes for all periods presented. For further discussion of segment reporting, refer to Note 20, Segment Reporting .
Discontinued Operations	Discontinued Operations On December 31, 2018, as described in Note 4, 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 was recast in 2018 to reflect the presentation of these entities as discontinued operations. On August 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions
Basis of Presentation	The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
Principles of Consolidation	The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Funds Deposited by Counterparties	Funds Deposited by Counterparties Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if twelve
Credit Losses	Credit Losses On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments , or ASU No. 2016-13, using the modified retrospective approach. Following the adoption of the new standard, the Company’s process of estimating expected credit losses remains materially consistent with its historical practice. Information prior to January 1, 2020, which was previously referred to as the allowance and provision for bad debt, has not been restated and continues to be reported under the accounting standards in effect for that period. Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues an allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and industrial customers. The Company writes off customer contract receivable balances against the allowance for credit losses when it is determined a receivable is uncollectible.
Restricted Cash	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, (In millions) 2020 2019 2018 Cash and cash equivalents $ 3,905 $ 345 $ 563 Funds deposited by counterparties 19 32 33 Restricted cash 6 8 17 Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows $ 3,930 $ 385 $ 613
Inventory	Inventory Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at weighted average cost. The Company removes these inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the fuel oil, coal, raw materials, and spare parts costs in the ordinary course of business. Finished goods inventory is valued at the lower of cost or net realizable value with cost being determined on a first-in first-out basis. The Company removes these inventories as they are sold to customers. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however, impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. 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
Asset Impairments	Asset Impairments Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is indicated if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the consolidated statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets, and present value techniques. Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures , or ASC 323, which requires that a loss in value of an investment that is an other-than-temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value. For further discussion of these matters, refer to Note 11, Asset Impairments .
Development Costs and Capitalized Interest	Development Costs and Capitalized Interest Development costs include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized interest and capitalized project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt, or as an asset if the issuance costs relate to revolving debt agreements or certain other financing arrangements.
Intangible Assets	Intangible Assets Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, 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, 2020 and 2019, the Company had accumulated amortization related to its intangible assets of $1.4 billion and $1.3 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	Goodwill In accordance with ASC 350, Intangibles-Goodwill and Other , or 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.
Income Taxes	Income Taxes The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or 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 expected to be in effect when the deferred tax is realized. 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 is the amount of benefit that has surpassed the more-likely-than-not threshold, as it 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 21, Income Taxes , changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax (benefit)/expense.
Contract Amortization	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 or more than market are amortized to cost of operations over the term of each underlying contract based on actual generation and/or contracted volumes. Revenue from Contracts with Customers On January 1, 2018, the Company adopted the guidance in ASC 606, Revenue from Contracts with Customers, or 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 $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 Company's policies with respect to its various revenue streams are detailed below. The Company generally 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 Revenue 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 and natural gas contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity and natural gas products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligations 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, utilities, 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 and natural gas 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 consist of revenues billed to a third party at either market or negotiated contract terms 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 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 used to hedge the sale of electricity are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815. Capacity Revenue The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE and NYISO. Capacity revenues also include revenues billed to a third party at either market or negotiated contract terms 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 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.
Lease Revenue and Lessor Accounting	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 842, 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. 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 842 . Sale-Leaseback Arrangements NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneously leases back the same asset to the Company. If the seller-lessee transfers control of the underlying assets to the buyer-lessor, the arrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as operating leases on the Company's consolidated balance sheets. See Note 10, Leases, for further discussion.
Gross Receipts and Sales Taxes	Gross Receipts and Sales Taxes In connection with its retail sales, 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, 2020, 2019 and 2018, the Company's revenues and cost of operations included gross receipts taxes of $107 million, $109 million and $99 million,
Purchased Energy and Other Cost of Sales for Customer Operations	Purchased Energy and Other Cost of Sales for Customer Operations The cost of energy for electricity sales and services to retail customers is included in cost of operations and is based on actual and estimated supply volumes for the applicable reporting period. A portion of the cost of energy, $98 million, $103 million and $105 million as of December 31, 2020, 2019 and 2018, 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	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, and other energy related commodities 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. The Company had no cash flow hedges as of December 31, 2020. Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings. NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
Foreign Currency Translation and Transaction Gains and Losses	Foreign Currency Translation and Transaction Gains and LossesThe 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.
Concentrations of Credit Risk	Concentrations of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 5, Fair Value of Financial Instruments, for a further discussion of derivative concentrations.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payable, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 5, Fair Value of Financial Instruments, for a further discussion of fair value of financial instruments.
Asset Retirement Obligations	Asset Retirement Obligations The Company accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made. Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 15, Asset Retirement Obligations, for a further discussion of AROs.
Pensions and Other Postretirement Benefits	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 , or ASC 715 . 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,
Stock-Based Compensation	Stock-Based Compensation The Company accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718 . The fair value of the Company's performance stock units is estimated on the date of grant using a Monte Carlo valuation model. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's deferred stock units. The fair value of the Company's restricted stock units is derived from the closing price of NRG's common stock at the grant date. Forfeiture rates are estimated based on an analysis of the Company's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award.
Investments Accounted for by the Equity Method	Investments Accounted for by the Equity MethodThe 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	Tax Equity Arrangements The Company’s redeemable noncontrolling interest in subsidiaries represented third-party interests in the net assets under certain tax equity arrangements, which were consolidated by the Company, that had been entered into to finance the cost of solar energy systems under operating leases. The Company determined that the provisions in the contractual agreements of these structures represented substantive profit sharing arrangements. Further, the Company had determined that the appropriate methodology for calculating the redeemable noncontrolling interest that reflected the substantive profit sharing arrangements was a balance sheet approach that utilized the HLBV method. Under the HLBV method, the amounts reported as redeemable noncontrolling interests represented the amounts the investors that were 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. The investors’ interests in the results of operations of the funding structures were determined as 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 included estimated calculations of taxable income or losses for each reporting period. During the first quarter of 2020, the Company repurchased its partners' equity interest as further described in Note 18, Investments Accounted for by the Equity Method and Variable Interest Entities . The Company has no remaining tax equity arrangements as of December 31, 2020.
Redeemable Noncontrolling Interest	Redeemable Noncontrolling InterestTo the extent that the third-party has the right to redeem their interests for cash or other assets, the Company had included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet.
Sale-Leaseback Arrangements	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 842, 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. 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 842 . Sale-Leaseback Arrangements NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneously leases back the same asset to the Company. If the seller-lessee transfers control of the underlying assets to the buyer-lessor, the arrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as operating leases on the Company's consolidated balance sheets. See Note 10, Leases, for further discussion.
Marketing and Advertising Costs	Marketing and Advertising CostsThe Company expenses its marketing and advertising costs as incurred and includes them 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.
Reorganization Costs	Reorganization CostsReorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily reflect severance and contract modifications.
Business Combinations	Business Combinations The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805, which 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. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination. In addition, transaction costs are expensed as incurred.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications	Reclassifications Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.
Recent Accounting Developments	Recent Accounting Developments - Guidance Adopted in 2020 ASU 2020-09 — In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470) - Amendments to SEC Paragraphs Pursuant to SEC Release No. 33-10762 , or ASU 2020-09, to reflect the SEC’s amended disclosure rules for guaranteed debt securities offerings. The final rule amends the disclosure requirements in SEC Regulation S-X, Rule 3-10, which require entities to separately present financial statements for subsidiary issuers and guarantors of registered debt securities unless certain exceptions are met. The amended rule allows entities to provide summarized financial information of the parent company and its issuers and guarantors on a combined basis either in a note to the financial statements or as part of management’s discussion and analysis. ASU 2020-09 is effective for filings on or after January 4, 2021, with early adoption permitted. The Company adopted the amendments effective December 31, 2020. As the amendments contemplate changes in disclosures only, it did not have an impact on the Company's results of operations, cash flows, or statement of financial position. 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 , or ASU No. 2018-17, in response to stakeholders’ observations that Topic 810, Consolidations , could be improved thereby improving general purpose financial reporting. Specifically, ASU No. 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 Company adopted the amendments effective January 1, 2020 using the retrospective approach. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position. ASU 2018-15 — In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in Cloud Computing Arrangement That Is a Service Contract , or ASU No. 2018-15. The amendments in ASU No. 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs incurred to develop or obtain internal-use software (and hosting arrangement that include an internal-use software license). The amendment also requires the customer to amortize the capitalized implementation costs of a hosting arrangement that is a service contract over the term of the hosting arrangement. The Company adopted the amendments effective January 1, 2020 using the prospective approach. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position. 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 amendments in ASU No. 2018-13 eliminate such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy and add new disclosure requirements for Level 3 measurements. The Company adopted the amendments effective January 1, 2020. Certain disclosures in ASU No. 2018-13 were applied on a retrospective basis and others on a prospective basis as required. As the amendments contemplates changes in disclosures only, it did not have an impact on the Company's results of operations, cash flows, or statement of financial position. ASU 2016-13 — In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Statements, or ASU No. 2016-13, which was further amended through various updates issued by the FASB thereafter. The guidance in ASU No. 2016-13 provides a new model for recognizing credit losses on financial assets carried at amortized cost using an estimate of expected credit losses, instead of the "incurred loss" methodology previously required for recognizing credit losses that delayed recognition until it was probable that a loss was incurred. The estimate of expected credit losses is to be based on consideration of past events, current conditions and reasonable and supportable forecasts of future conditions. The Company adopted the standard and its subsequent corresponding updates effective January 1, 2020 using the modified retrospective approach. Results for the reporting periods after January 1, 2020 are presented under Topic 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company's adoption of Topic 326 did not have a material impact on the Company's results of operations, cash flows, or statement of financial position. Recent Accounting Developments - Guidance Not Yet Adopted ASU 2020-06 — In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) , or ASU No. 2020-06. The guidance in ASU 2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock. In addition, ASU 2020-06 improves and amends the related earnings per share guidance. This standard is effective for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years. Early adoption is permitted in fiscal years beginning after December 15, 2020, including interim periods within those fiscal years. The Company is currently in the process of assessing the impact of this guidance on the consolidated financial statements and disclosures related to earnings per share. ASU 2019-12 — In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,
Revenue Recognition	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 or more than market are amortized to cost of operations over the term of each underlying contract based on actual generation and/or contracted volumes. Revenue from Contracts with Customers On January 1, 2018, the Company adopted the guidance in ASC 606, Revenue from Contracts with Customers, or 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 $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 Company's policies with respect to its various revenue streams are detailed below. The Company generally 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 Revenue 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 and natural gas contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity and natural gas products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligations 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, utilities, 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 and natural gas 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 consist of revenues billed to a third party at either market or negotiated contract terms 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 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 used to hedge the sale of electricity are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815. Capacity Revenue The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE and NYISO. Capacity revenues also include revenues billed to a third party at either market or negotiated contract terms 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 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.
Nuclear Decommissioning Policy	NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations , or ASC 980, because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
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, (In millions) 2020 2019 2018 Income from continuing operations, net of income tax $ 510 $ 4,117 $ 465 Income/(loss) from discontinued operations, net of income tax — 321 (197) Net income attributable to NRG Energy, Inc. stockholders $ 510 $ 4,438 $ 268
Accounts Receivable, Allowance for Credit Loss	The following table represents the activity in the allowance for credit losses for the year ended December 31, 2020: (In millions) Year Ended December 31, 2020 Beginning balance $ 43 Provision for credit losses 108 Write-offs (101) Recoveries collected 17 Ending balance $ 67
Reconciliation of cash, cash equivalents, and restricted cash and cash equivalents	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, (In millions) 2020 2019 2018 Cash and cash equivalents $ 3,905 $ 345 $ 563 Funds deposited by counterparties 19 32 33 Restricted cash 6 8 17 Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows $ 3,930 $ 385 $ 613 Detail of supplemental disclosures of cash flow and non-cash investing and financing information was: Year Ended December 31, (In millions) 2020 2019 2018 Interest paid, net of amount capitalized $ 340 $ 372 $ 436 Income taxes paid, net of refunds 24 8 9 Non-cash investing activities: (Decreases)/additions to fixed assets for accrued capital expenditures (6) 1 20
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, 2020, 2019 and 2018. (In millions) 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 Distributions to redeemable noncontrolling interest (2) Net income attributable to redeemable noncontrolling interest - continuing operations 3 Balance as of December 31, 2019 20 Repurchase of redeemable noncontrolling interest (20) Balance as of December 31, 2020 $ — (a) See Note 4, Acquisitions, Discontinued Operations and Dispositions , for further information regarding the sale of NRG Yield and its Renewables Platform

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following tables represent the Company’s disaggregation of revenue from contracts with customers for the years ended December 31, 2020, 2019 and 2018: For the Year Ended December 31, 2020 (In millions) Texas East West/Other Corporate/Eliminations Total Retail revenue Mass Market $ 5,027 $ 1,306 $ — $ (2) $ 6,331 Business Solutions 1,034 95 — — 1,129 Total retail revenue 6,061 1,401 — (2) 7,460 Energy revenue (a) 24 183 333 (1) 539 Capacity revenue (a) — 620 61 (1) 680 Mark-to-market for economic hedging activities (b) 2 88 (3) 8 95 Other revenue (a) 222 62 43 (8) 319 Total operating revenue 6,309 2,354 434 (4) 9,093 Less: Lease revenue — 1 17 — 18 Less: Realized and unrealized ASC 815 revenue 30 314 38 3 385 Total revenue from contracts with customers $ 6,279 $ 2,039 $ 379 $ (7) $ 8,690 (a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: (In millions) Texas East West/Other Corporate/Eliminations Total Energy revenue $ — $ 67 $ 43 $ (5) $ 105 Capacity revenue — 156 — — 156 Other revenue 28 3 (2) — 29 (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 For the Year Ended December 31, 2019 (In millions) Texas East West/Other Corporate/Eliminations Total Retail revenue Mass Market $ 5,027 $ 1,230 $ — $ (3) $ 6,254 Business Solutions 1,205 74 — — 1,279 Total retail revenue 6,232 1,304 — (3) 7,533 Energy revenue (a) 529 322 318 — 1,169 Capacity revenue (a) — 664 36 — 700 Mark-to-market for economic hedging activities (b) 47 (29) 16 (1) 33 Other revenue (a)(c) 261 58 70 (3) 386 Total operating revenue 7,069 2,319 440 (7) 9,821 Less: Lease revenue — 1 19 — 20 Less: Realized and unrealized ASC 815 revenue 1,562 183 67 (2) 1,810 Total revenue from contracts with customers $ 5,507 $ 2,135 $ 354 $ (5) $ 7,991 (a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: (In millions) Texas East West/Other Corporate/Eliminations Total Energy revenue $ 1,459 $ 98 $ 39 $ (1) $ 1,595 Capacity revenue — 109 — — 109 Other revenue 56 5 12 — 73 (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 For the Year Ended December 31, 2018 (In millions) Texas East West/Other Corporate/Eliminations Total Retail revenue Mass Market $ 4,618 $ 974 $ — $ (1) $ 5,591 Business Solutions 1,238 65 — — 1,303 Total retail revenue 5,856 1,039 — (1) 6,894 Energy revenue (a) 371 546 566 13 1,496 Capacity revenue (a) — 746 79 — 825 Mark-to-market for economic hedging activities (b) (77) (35) (5) (13) (130) Other revenue (a)(c) 251 75 84 (17) 393 Total operating revenue 6,401 2,371 724 (18) 9,478 Less: Lease revenue 1 1 19 — 21 Less: Realized and unrealized ASC 815 revenue 1,096 210 2 1 1,309 Total revenue from contracts with customers $ 5,304 $ 2,160 $ 703 $ (19) $ 8,148 (a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: (In millions) Texas East West/Other Corporate/Eliminations Total Energy revenue $ 1,131 $ 90 $ (2) $ 14 $ 1,233 Capacity revenue — 137 — — 137 Other revenue 42 17 9 1 69 (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
Contract Assets and Liabilities	The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31, 2020 and 2019: (In millions) December 31, 2020 December 31, 2019 Deferred customer acquisition costs $ 113 $ 133 Accounts receivable, net - Contracts with customers 866 1,002 Accounts receivable, net - Derivative instruments 33 18 Accounts receivable, net - Affiliate 5 5 Total accounts receivable, net $ 904 $ 1,025 Unbilled revenues (included within Accounts receivable, net - Contracts with customers) $ 393 $ 402 Deferred revenues (a) $ 60 $ 82 (a) Deferred revenues from contracts with customers for the years ended December 31, 2020 and 2019 were approximately $31 million and $24 million, respectively.

Acquisitions, Discontinued Op_2

Acquisitions, Discontinued Operations and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2020
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Collective Collateral Facilities	The Company also increased its collective collateral facilities by $3.4 billion as of the Acquisition Closing Date to meet the additional liquidity requirements related to the acquisition, as detailed in the following table: (In millions) December 31, 2020 Revolving Credit Facility commitment increase (a) $ 802 Revolving Credit Facility new tranche (a) 273 Credit default swap facility 150 Revolving accounts receivable financing facility 750 Repurchase facility 75 Facility agreement in connection with the sale of pre-capitalized trust securities (a) 874 Bilateral letter of credit facilities 475 Total Increases to Liquidity and Collateral Facilities $ 3,399 (a) Available upon the Acquisition Closing Date
Schedule of Purchase Price Allocation	The purchase price is provisionally allocated as follows: (In millions) Assets Cash and cash equivalents $ 152 Current assets 3,374 Property, plant and equipment 166 Goodwill and other intangibles (a) 3,446 Other non-current assets 687 Total assets acquired 7,825 Liabilities Current liabilities 3,085 Non-current liabilities 1,038 Total liabilities assumed 4,123 Direct Energy Purchase Price $ 3,702 (a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of Direct Energy with NRG's existing businesses. (In millions) Account receivable $ 98 Accounts payable (73) Other net current and non-current working capital 5 Marketing partnership 154 Customer relationships 85 Trade name 28 Other intangible assets 26 Goodwill (a) 6 Stream Purchase Price $ 329 (a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of Stream Energy with NRG's existing businesses. Goodwill of $5 million and $1 million was assigned to the Texas and East segments, respectively, and is not deductible for tax purposes (In millions) Net current and non-current working capital $ 46 Other intangible assets 133 Goodwill 34 XOOM Purchase Price $ 213 (a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of XOOM Energy with NRG's existing businesses. Goodwill of $28 million and $6 million was assigned to the Texas and East segments, respectively, and is deductible for tax purposes
Summary of Results of Discontinued Operations	Summarized results of South Central discontinued operations were as follows: Year Ended December 31, (In millions) 2019 2018 Operating revenues $ 31 $ 410 Operating costs and expenses (23) (346) Other income — 2 Gain from operations of discontinued components 8 66 Gain on disposal of discontinued operations, net of tax 20 — Gain from discontinued operations, including disposal, net of tax $ 28 $ 66 Summarized results of NRG Yield, Inc. and Renewables Platform and Carlsbad discontinued operations were as follows: (In millions) 2019 2018 Operating revenues $ 19 $ 909 Operating costs and expenses (9) (661) Other expenses (5) (174) Gain/(loss) from operations of discontinued components, before tax 5 74 Income tax expense — 4 Gain/(loss) from discontinued operations, net of tax 5 70 Gain/(loss) on disposal of discontinued operations, net of tax 265 (134) Income/(expense) from California property tax indemnification 22 (153) Income/(expense) from other commitments, indemnification and fees 4 (75) Income/(loss) on disposal of discontinued operations, net of tax 291 (362) Income/(loss) from discontinued operations, net of tax $ 296 $ (292) Summarized results of discontinued operations were as follows: Year Ended December 31, (In millions) 2019 2018 Interest income - affiliate $ — $ 3 Income/(loss) from discontinued operations, net of tax — 3 Settlement consideration, insurance and services credit — 63 Pension and post-retirement liability assumption — 21 Other (3) (53) (Loss)/income on disposal of discontinued operations, net of tax (3) 31 (Loss)/income from discontinued operations, net of tax $ (3) $ 34

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 (In millions) Carrying Amount Fair Value Carrying Amount Fair Value Assets Notes receivable $ 2 $ 2 $ 11 $ 8 Liabilities Long-term debt, including current portion (a) $ 8,781 $ 9,446 $ 5,956 $ 6,504 (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, 2020 and 2019: As of December 31, 2020 As of December 31, 2019 (In millions) Level 2 Level 3 Level 2 Level 3 Long-term debt, including current portion $ 9,446 $ — $ 6,388 $ 116
Assets and Liabilities Measured and Recorded at Fair Value Measured on a Recurring Basis	The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy: As of December 31, 2020 Fair Value (In millions) Total Level 1 Level 2 Level 3 Investments in securities (classified within other current and non-current assets) $ 25 $ 10 $ 15 $ — Nuclear trust fund investments: Cash and cash equivalents 23 23 — — U.S. government and federal agency obligations 70 69 1 — Federal agency mortgage-backed securities 89 — 89 — Commercial mortgage-backed securities 36 — 36 — Corporate debt securities 144 — 144 — Equity securities 434 434 — — Foreign government fixed income securities 7 1 6 — Other trust fund investments: U.S. government and federal agency obligations 1 1 — — Derivative assets: Commodity contracts 821 59 623 139 Measured using net asset value practical expedient: Equity securities-nuclear trust fund investments 87 — — — Equity securities 8 — — — Total assets $ 1,745 $ 597 $ 914 $ 139 Derivative liabilities: Commodity contracts $ 884 $ 86 $ 643 $ 155 Total liabilities $ 884 $ 86 $ 643 $ 155 As of December 31, 2019 Fair Value (In millions) Total Level 1 Level 2 Level 3 Investments in securities (classified within other current or non-current assets) $ 20 $ — $ 20 $ — Nuclear trust fund investments: Cash and cash equivalents 17 17 — — U.S. government and federal agency obligations 68 68 — — Federal agency mortgage-backed securities 100 — 100 — Commercial mortgage-backed securities 29 — 29 — Corporate debt securities 109 — 109 — Equity securities 388 388 — — Foreign government fixed income securities 5 — 5 — Other trust fund investments: U.S. government and federal agency obligations 1 1 — — Derivative assets: Commodity contracts 1,170 84 893 193 Measured using net asset value practical expedient: Equity securities-nuclear trust fund investments 78 — — — Equity securities 8 — — — Total assets $ 1,993 $ 558 $ 1,156 $ 193 Derivative liabilities: Commodity contracts $ 1,103 $ 143 $ 805 $ 155 Total liabilities $ 1,103 $ 143 $ 805 $ 155
Reconciliation of Beginning and Ending Balances for Financial Instruments that are Recognized at Fair Value using Significant Unobservable Inputs	The following tables reconcile, for the years ended December 31, 2020 and 2019, 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, 2020 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) (In millions) Derivatives (a) Beginning balance as of January 1, 2020 $ 38 Total (losses) — realized/unrealized included in earnings (44) Purchases (13) Transfers into Level 3 (b) 1 Transfers out of Level 3 (b) 2 Ending balance as of December 31, 2020 $ (16) 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, 2020 $ 9 (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, 2019 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) (In millions) Debt Securities Derivatives (a) Total Beginning balance as of January 1, 2019 $ 19 $ 20 $ 39 Contracts added from acquisitions — (3) $ (3) Total (losses) — realized/unrealized included in earnings — (26) (26) Purchases — 40 40 Sale (19) — (19) Transfers into Level 3 (b) — 2 2 Transfers out of Level 3 (b) — 5 5 Ending balance as of December 31, 2019 $ — $ 38 $ 38 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, 2019 $ — $ 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
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, 2020 and 2019: Significant Unobservable Inputs December 31, 2020 Fair Value Input/Range (In millions) Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average Power Contracts $ 111 $ 143 Discounted Cash Flow Forward Market Price (per MWh) $ 10 $ 105 $ 21 FTRs 28 12 Discounted Cash Flow Auction Prices (per MWh) (28) 43 0 $ 139 $ 155 Significant Unobservable Inputs December 31, 2019 Fair Value Input/Range (In millions) Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average Power Contracts $ 151 $ 139 Discounted Cash Flow Forward Market Price (per MWh) $ 8 $ 218 $ 24 FTRs 42 16 Discounted Cash Flow Auction Prices (per MWh) (105) 213 0 $ 193 $ 155
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, 2020 and 2019: 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 96 % Financial institutions 4 Total 100 % Category Net Exposure (a) (b) (% of Total) Investment grade 59 % Non-Investment grade/Non-Rated 41 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 Ins_2

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net Notional Volume Buy/(sell) of NRG's Open Derivative Transactions Broken Out By Commodity	The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2020 and 2019. 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. (In millions) Total Volume Commodity Units December 31, 2020 December 31, 2019 Emissions Short Ton 1 3 Renewables Energy Certificates Certificates 5 1 Coal Short Ton 2 10 Natural Gas MMBtu (286) (181) Power MWh 57 38 Capacity MW/Day (1) (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, 2020 December 31, 2019 December 31, 2020 December 31, 2019 Derivatives Not Designated as Cash Flow or Fair Value Hedges : Commodity contracts current $ 560 $ 860 $ 499 $ 781 Commodity contracts long-term 261 310 385 322 Total Derivatives Not Designated as Cash Flow or Fair Value Hedges $ 821 $ 1,170 $ 884 $ 1,103
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 (In millions) Gross Amounts of Recognized Assets/Liabilities Derivative Instruments Cash Collateral (Held)/Posted Net Amount As of December 31, 2020 Commodity contracts: Derivative assets $ 821 $ (658) $ (5) $ 158 Derivative liabilities (884) 658 — (226) Total commodity contracts $ (63) $ — $ (5) $ (68) Gross Amounts Not Offset in the Statement of Financial Position (In millions) Gross Amounts of Recognized Assets/Liabilities Derivative Instruments Cash Collateral (Held)/Posted Net Amount As of December 31, 2019 Commodity contracts: Derivative assets $ 1,170 $ (909) $ (7) $ 254 Derivative liabilities (1,103) 909 73 (121) Total commodity contracts $ 67 $ — $ 66 $ 133
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, for the year 2018: Interest Rate Contracts (In millions) 2018 Accumulated OCI beginning balance $ (54) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts 8 Mark-to-market of cash flow hedge accounting contracts 21 Sale of NRG Yield and Renewables 25 Accumulated OCI ending balance $ —
Pre-tax Effects of Economic Hedges That Have Not Been Designated As Cash Flow Hedges, Ineffectiveness On Cash Flow Hedges And Trading Activity on the Company's Statement of Operations	The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges or fair value 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, (In millions) 2020 2019 2018 Unrealized mark-to-market results Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges $ (55) $ (68) $ (73) Reversal of acquired loss/(gain) positions related to economic hedges 4 6 (10) Net unrealized (losses)/gains on open positions related to economic hedges (68) 42 97 Total unrealized mark-to-market (losses)/gains for economic hedging activities (119) (20) 14 Reversal of previously recognized unrealized (gains) on settled positions related to trading activity (20) (11) (12) Net unrealized gains on open positions related to trading activity 15 31 29 Total unrealized mark-to-market (losses)/gains for trading activity (5) 20 17 Total unrealized (losses)/gains $ (124) $ — $ 31 Year Ended December 31, (In millions) 2020 2019 2018 Unrealized gains/(losses) included in operating revenues $ 90 $ 53 $ (113) Unrealized (losses)/gains included in cost of operations (214) (53) 144 Total impact to statement of operations — energy commodities $ (124) $ — $ 31 Total impact to statement of operations — interest rate contracts $ — $ (38) $ —

Nuclear Decommissioning Trust_2

Nuclear Decommissioning Trust Fund (Tables)	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Summary of Aggregate Fair Values and Unrealized Gains And Losses (Including Other-Than-Temporary Impairments) for the Securities Held in The Nuclear Decommissioning Trust Fund	The following table summarizes the aggregate fair values and unrealized gains and losses for the securities held in the trust funds, as well as information about the contractual maturities of those securities. As of December 31, 2020 As of December 31, 2019 (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 $ 23 $ — $ — — $ 17 $ — $ — — U.S. government and federal agency obligations 70 6 — 10 68 4 — 11 Federal agency mortgage-backed securities 89 4 — 24 100 3 — 24 Commercial mortgage-backed securities 36 2 — 27 29 1 1 24 Corporate debt securities 144 13 — 12 109 6 — 11 Equity securities 521 372 — — 466 324 — — Foreign government fixed income securities 7 1 — 10 5 — — 10 Total $ 890 $ 398 $ — $ 794 $ 338 $ 1
Summary of Proceeds From Sales of Available-For-Sale securities and the related realized gains and losses	The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined using the specific identification method. Year Ended December 31, (In millions) 2020 2019 2018 Realized gains $ 34 $ 18 $ 17 Realized (losses) (13) (9) (13) Proceeds from sale of securities 439 381 513

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2020
Inventory Disclosure [Abstract]
Schedule of Inventory	Inventory consisted of: As of December 31, (In millions) 2020 2019 Fuel oil $ 37 $ 73 Coal 73 93 Natural gas 22 21 Spare parts 195 196 Total Inventory $ 327 $ 383

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
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 (In millions) 2020 2019 Lives Facilities and equipment $ 3,365 $ 3,262 1-40 years Land and improvements 329 324 Nuclear fuel 239 235 5 years Hardware and office equipment and furnishings 453 422 2-10 years Construction in progress 97 102 Total property, plant, and equipment 4,483 4,345 Accumulated depreciation (1,936) (1,752) Net property, plant, and equipment $ 2,547 $ 2,593

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Lease Cost	Lease Cost: (In millions) For the Year Ended December 31, 2020 For the Year Ended December 31, 2019 Finance lease cost $ 3 $ — Operating lease cost 100 109 Short-term lease cost 3 3 Variable lease cost 6 6 Sublease income (17) (17) Total lease cost $ 95 $ 101 Other information: (In millions) For the Year Ended December 31, 2020 For the Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 101 $ 104 Financing cash flows from finance leases 1 — Right-of-use assets obtained in exchange for new finance lease liabilities 5 — Right-of-use assets obtained in exchange for new operating lease liabilities 4 215 Lease Term and Discount Rate for leases: December 31, 2020 December 31, 2019 Finance leases: Weighted average remaining lease term (in years) 1.1 — Weighted average discount rate 4.79 % — Operating leases: Weighted average remaining lease term (in years) 5.3 7.8 Weighted average discount rate 5.63 % 5.72 %
Schedule of Annual Payments Based on Maturities of Leases	As of December 31, 2020, annual payments based on the maturities of NRG's leases are expected to be as follows: (In millions) 2021 $ 86 2022 82 2023 81 2024 71 2025 47 Thereafter 34 Total undiscounted lease payments $ 401 Less: present value adjustment (54) Total discounted lease payments $ 347

Goodwill and Other Intangibles

Goodwill and Other Intangibles (Tables)	12 Months Ended
	Dec. 31, 2020
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: (In millions) Year Ended December 31, 2020 Emission Allowances Fuel Contracts Customer Relationships Marketing Partnerships Trade Names Other (b) Total January 1, 2020 $ 662 $ 49 $ 573 $ 285 $ 373 $ 109 $ 2,051 Purchases 25 — — — — 45 70 Acquisition of businesses (a) — — 22 — — — 22 Retirements — — — — — (35) (35) Write-off of fully amortized balances (4) — (70) — — — (74) Impairment (14) — — — — — (14) Other 3 — 2 — — — 5 December 31, 2020 672 49 527 285 373 119 2,025 Less accumulated amortization (563) (46) (349) (99) (247) (53) (1,357) Net carrying amount $ 109 $ 3 $ 178 $ 186 $ 126 $ 66 $ 668 (a) The weighted average life of acquired intangibles was 5 years for customer relationships (b) RECs are not subject to amortization and had a carrying value of $28 million (In millions) Year Ended December 31, 2019 Emission Allowances Fuel Contracts Customer Relationships Marketing Partnerships Trade Names Other (b) Total January 1, 2019 $ 659 $ 49 $ 478 $ 131 $ 345 $ 80 $ 1,742 Purchases 13 — — — — 29 42 Acquisition of businesses (a) — — 110 154 28 26 318 Usage/Retirements (4) — — — — (17) (21) Write-off of fully amortized balances (8) — (13) — — (9) (30) Impairment — — (2) — — — (2) Other 2 — — — — — 2 December 31, 2019 662 49 573 285 373 109 2,051 Less accumulated amortization (539) (45) (345) (75) (220) (38) (1,262) Net carrying amount $ 123 $ 4 $ 228 $ 210 $ 153 $ 71 $ 789 (a) The weighted average life of acquired intangibles was: customer relationships 7 years, trade names 12 years, marketing partnerships 9 years, and energy supply contracts 2 years (b) RECs are not subject to amortization and had a carrying value of $18 million
Schedule of Amortization and Retirements of Intangible Expense	The following table presents NRG's amortization and retirements of intangible assets for each of the past three years: Years Ended December 31, (In millions) 2020 2019 2018 Emission allowances $ 28 $ 32 $ 39 Customer relationships 74 44 32 Marketing partnerships 24 15 9 Trade names 27 25 23 Other (a) 51 35 30 Total amortization $ 204 $ 151 $ 133
Schedule of Estimated Amortization of Intangible Assets for Next Five Years	The following table presents estimated amortization of NRG's intangible assets as of December 31, 2020 for each of the next five years: (In millions) Year Ended December 31, Emission Allowances Fuel Contracts Customer Relationships Marketing Partnerships Trade Names Other Total 2021 $ 31 $ — $ 64 $ 24 $ 27 $ 3 $ 149 2022 30 1 44 23 27 3 128 2023 30 — 45 23 26 3 127 2024 31 1 16 23 17 3 91 2025 29 — 5 22 11 3 70

Long-term Debt and Finance Le_2

Long-term Debt and Finance Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-term Debt and Finance Leases	Long-term debt and finance leases consisted of the following: (In millions, except rates) December 31, 2020 December 31, 2019 Interest rate % Recourse debt: Senior Notes, due 2026 $ 1,000 $ 1,000 7.250 Senior Notes, due 2027 1,230 1,230 6.625 Senior Notes, due 2028 821 821 5.750 Senior Notes, due 2029 733 733 5.250 Senior Notes, due 2029 500 — 3.375 Senior Notes, due 2031 1,030 — 3.625 Convertible Senior Notes, due 2048 (a) 575 575 2.750 Senior Secured First Lien Notes, due 2024 600 600 3.750 Senior Secured First Lien Notes, due 2025 500 — 2.000 Senior Secured First Lien Notes, due 2027 900 — 2.450 Senior Secured First Lien Notes, due 2029 500 500 4.450 Revolving Credit Facility — 83 L+ 1.75 Tax-exempt bonds 466 466 1.250 - 4.75 Subtotal recourse debt 8,855 6,008 Non-recourse debt: Other — 34 various Subtotal all non-recourse debt — 34 Subtotal long-term debt (including current maturities) 8,855 6,042 Finance leases 4 — various Subtotal long-term debt and finance leases (including current maturities) 8,859 6,042 Less current maturities (1) (88) Less debt issuance costs (93) (65) Discounts (74) (86) Total long-term debt and finance leases $ 8,691 $ 5,803 (a) The effective interest rate was 5.19% and 5.05% for the years ended December 31, 2020 and 2019, respectively. As of the ex-dividend date of January 29, 2021, the Convertible Notes were convertible at a price of $45.94, which is equivalent to a conversion rate of approximately 21.77 shares of common stock per $1,000 principal amount. The remaining period over which the discount on the liability component will be amortized is 4.7 years. Debt includes the following discounts: As of December 31, (In millions) 2020 2019 Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029 $ (2) $ (1) Convertible Senior Notes, due 2048 (72) (85) Total discounts $ (74) $ (86)
Annual Payments Based On the Maturities of NRG's Debt	As of December 31, 2020, annual payments based on the maturities of NRG's debt and finance leases are expected to be as follows: (In millions) 2021 $ 1 2022 2 2023 1 2024 600 2025 500 Thereafter 7,755 Total $ 8,859
Debt Redemption	In addition, on or after May 15, 2021, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption 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 % Redemption Period Redemption July 15, 2021 to July 14, 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 % Redemption Period Redemption 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 % Redemption Period Redemption Percentage June 15, 2024 to June 14, 2025 102.625 % June 15, 2025 to June 14, 2026 101.750 % June 15, 2026 to June 14, 2027 100.875 % June 15, 2027 and thereafter 100.000 % Redemption Period Redemption Percentage February 15, 2024 to February 14, 2025 101.688 % February 15, 2025 to February 14, 2026 100.844 % February 15, 2026 and thereafter 100.000 % Redemption Period Redemption Percentage February 15, 2026 to February 14, 2027 101.813 % February 15, 2027 to February 14, 2028 101.208 % February 15, 2028 to February 14, 2029 100.604 % February 15, 2029 and thereafter 100.000 %
Schedule of Tax Exempt Bonds	Tax Exempt Bonds As of December 31, (In millions, except rates) 2020 2019 Interest Rate % NRG Indian River Power 2020, tax exempt bonds, due 2040 $ 57 $ — 1.250 NRG Indian River Power 2020, tax exempt bonds, due 2045 190 — 1.250 Indian River Power, tax exempt bonds, due 2040 — 57 6.000 Indian River Power LLC, tax exempt bonds, due 2045 — 190 5.375 NRG Dunkirk 2020, tax exempt bonds, due 2042 59 — 1.300 Dunkirk Power LLC, tax exempt bonds, due 2042 — 59 5.875 City of Texas City, tax exempt bonds, due 2045 33 33 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 $ 466

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Schedule of ARO Obligations and Related Additions, Reductions and Accretion	The following table represents the balance of ARO obligations as of December 31, 2020 and 2019, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2020: (In millions) Nuclear Decommission Other (a) Total Balance as of December 31, 2019 $ 298 $ 430 $ 728 Revisions in estimates for current obligations (12) 38 26 Additions — 3 3 Spending for current obligations — (43) (43) Accretion 17 29 46 Balance as of December 31, 2020 $ 303 $ 457 $ 760 (a) Total accretion expense related to asset retirement obligations included in the consolidated statement of cash flows includes accretion and revisions in estimates for asset retirement liabilities on non-operating plants

Benefit Plans and Other Postr_2

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2020
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 (In millions) 2020 2019 2018 Service cost benefits earned $ 10 $ 10 $ 23 Interest cost on benefit obligation 38 46 44 Expected return on plan assets (61) (59) (62) Amortization of unrecognized net loss 5 3 — Settlement/curtailment expense — — 7 Net periodic benefit (credit)/cost $ (8) $ — $ 12 Year Ended December 31, Other Postretirement Benefits (In millions) 2020 2019 2018 Service cost benefits earned $ — $ 1 $ 1 Interest cost on benefit obligation 3 3 4 Amortization of unrecognized prior service cost (14) (13) (10) Amortization of unrecognized net loss 1 — — Curtailment gain — — (10) Net periodic benefit credit $ (10) $ (9) $ (15)
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 (In millions) 2020 2019 2020 2019 Benefit obligation at January 1 $ 1,397 $ 1,222 $ 93 $ 83 Service cost 10 10 — 1 Interest cost 38 46 3 3 Plan amendments — — — (2) Actuarial loss 126 207 — 16 Employee and retiree contributions — — 3 4 Benefit payments (82) (88) (9) (12) Benefit obligation at December 31 1,489 1,397 90 93 Fair value of plan assets at January 1 1,150 981 — — Actual return on plan assets 193 216 — — Employee and retiree contributions — — 3 4 Employer contributions 11 41 6 7 Benefit payments (82) (88) (9) (11) Fair value of plan assets at December 31 1,272 1,150 — — Funded status at December 31 — excess of obligation over assets $ (217) $ (247) $ (90) $ (93)
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 (In millions) 2020 2019 2020 2019 Other current liabilities $ — $ — $ 5 $ 7 Other non-current liabilities 217 247 85 86
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 (In millions) 2020 2019 2020 2019 Net loss $ 127 $ 138 $ 6 $ 7 Prior service cost/(credit) 2 2 (29) (43) Total accumulated OCI $ 129 $ 140 $ (23) $ (36)
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 (In millions) 2020 2019 2020 2019 Net actuarial (gain)/loss $ (6) $ 50 $ — $ 16 Amortization of net actuarial (gain) (5) (3) (1) — Prior service credit — — — (2) Amortization of prior service cost — — 14 12 Total recognized in OCI $ (11) $ 47 $ 13 $ 26 Net periodic benefit credit (8) — (10) (9) Net recognized in net periodic pension credit and OCI $ (19) $ 47 $ 3 $ 17
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 (In millions) 2020 2019 Projected benefit obligation $ 1,489 $ 1,397 Accumulated benefit obligation 1,455 1,362 Fair value of plan assets 1,272 1,150
Schedule of Fair Value of Pension Plan Assets by Asset Category and Level within the Fair Value Hierarchy	NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows: Fair Value Measurements as of December 31, 2020 (In millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total Common/collective trust investment — U.S. equity $ — $ 284 $ 284 Common/collective trust investment — non-U.S. equity — 113 113 Common/collective trust investment — non-core assets — 151 151 Common/collective trust investment — fixed income — 258 258 Short-term investment fund 13 — 13 Subtotal fair value $ 13 $ 806 $ 819 Measured at net asset value practical expedient: Common/collective trust investment — non-U.S. equity 45 Common/collective trust investment — fixed income 289 Common/collective trust investment — non-core assets 84 Partnerships/joint ventures 35 Total fair value $ 1,272 Fair Value Measurements as of December 31, 2019 (In millions) Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total Common/collective trust investment — U.S. equity $ — $ 233 $ 233 Common/collective trust investment — non-U.S. equity — 73 73 Common/collective trust investment — non-core assets — 143 143 Common/collective trust investment — fixed income — 272 272 Short-term investment fund 12 — 12 Subtotal fair value $ 12 $ 721 $ 733 Measured at net asset value practical expedient: Common/collective trust investment — non-U.S. equity 84 Common/collective trust investment — fixed income 279 Common/collective trust investment — non-core assets 24 Partnerships/joint ventures 30 Total fair value $ 1,150
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 2020 2019 2020 2019 Discount rate 2.56 % 3.26 % 2.54 % 3.26 % Interest crediting rate 3.12 % — 1.62 % — Rate of compensation increase 3.00 % 3.00 % — % — % Health care trend rate — — 7.2% grading to 4.5% in 2028 7.5% grading to 4.5% in 2028 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 2020 2019 2018 2020 2019 2018 Discount rate 3.26 % 4.38%/4.20% 3.71%/4.04% 3.26% 4.37% 3.71% /4.08% Interest crediting rate 3.66 % — — 2.28 % — — Expected return on plan assets 5.93 % 6.35 % 6.17 % — — — Rate of compensation increase 3.00 % 3.00 % 3.00 % — — — Health care trend rate — — — 7.5% grading to 4.5% in 2028 7.8% grading to 4.5% in 2025 8.2% grading to 4.5% 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, 2020: U.S. equity 20 % Non-U.S. equity 13 % Non-core assets 17 % U.S. fixed income 50 %
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 Short, Intermediate and Long Credits/Barclays Strips 20+ Index
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 (In millions) Pension Benefit Payments Benefit Payments Medicare Prescription Drug Reimbursements 2021 $ 90 $ 6 $ — 2022 89 6 — 2023 87 5 — 2024 85 5 — 2025 83 5 — 2026-2030 386 19 2
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 (In millions) 2020 2019 2020 2019 Funded status — STPNOC benefit plans $ (99) $ (77) $ (20) $ (20) Net periodic benefit cost/(credit) 7 9 (4) (4) Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss) 22 (13) 5 6
Defined Contribution Plan Contributions	The Company's contributions to these plans were as follows: Year Ended December 31, (In millions) 2020 2019 2018 Company contributions to defined contribution plans $ 22 $ 22 $ 28

Capital Structure (Tables)

Capital Structure (Tables)	12 Months Ended
	Dec. 31, 2020
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, 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 Shares issued under ESPP — 46,128 46,128 Shares issued under LTIPs 1,601,904 — 1,601,904 Share repurchases — (36,301,882) (36,301,882) Balance as of December 31, 2019 421,890,790 (172,894,601) 248,996,189 Shares issued under ESPP — 131,469 131,469 Shares issued under LTIPs 1,167,058 — 1,167,058 Share repurchases — (6,062,783) (6,062,783) Balance as of December 31, 2020 423,057,848 (178,825,915) 244,231,933
Summary of shares repurchased	The following table summarizes the shares repurchases made during the years 2018, 2019 and 2020: Total number of shares and share equivalents purchased Average price paid per share and share equivalent Amounts paid for shares and share equivalents purchased (in millions) 2018 repurchases: 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 Other repurchases 11,097,631 396 Total Share Repurchases during 2018 35,234,664 $ 35.48 $ 1,250 2019 repurchases: Repurchases under February 28, 2019 Accelerated Share Repurchase Agreement 9,438,671 400 Other repurchases 26,863,211 1,008 Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (a) 936,928 36 Total Share Repurchases during 2019 37,238,810 $ 38.79 $ 1,444 2020 repurchases: Repurchases 6,062,783 197 Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (a) 711,248 27 Total Share Repurchases during 2020 6,774,031 $ 33.05 $ 224 (a) NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management. The average price per equivalent shares withheld was $38.23 and $38.78 in 2020 and 2019, respectively. See Note 22, Stock-Based Compensation, for further discussion of the equity awards

Investments Accounted for by _2

Investments Accounted for by the Equity Method and Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020: (In millions, except percentages) Name Economic Investment Balance (a) Agua Caliente 35.0 % $ 185 Gladstone 37.5 % 131 Ivanpah Master Holdings, LLC 54.5 % 17 Watson Cogeneration Company 49.0 % 14 Midway-Sunset Cogeneration Company 50.0 % 12 Petra Nova Parish Holdings, LLC (b) 50.0 % (13) Total equity investments in affiliates $ 346 (a) As of December 31, 2020, the carry value of NRG's equity method investment was $343 million lower than the underlying net assets of the investees. The basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets. The basis difference is primarily due to impairments booked on Petra Nova, but not booked at the project level, as well as differences related to the deconsolidations of Ivanpah and Agua Caliente in 2018 and the treatment of certain deferred tax assets. (b) Refer to Note 11, Asset Impairments
Undistributed earnings by equity investment	As of December 31, (In millions) 2020 2019 Undistributed earnings from equity investments $ 30 $ 42
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, 2020 December 31, 2019 Accounts receivable $ 647 $ 3 Other current assets 2 — Net property, plant and equipment — 71 Other long-term assets — 27 Total assets 649 101 Current liabilities 78 4 Long-term debt — 24 Other long-term liabilities — 8 Total liabilities 78 36 Redeemable noncontrolling interests — 20 Net assets less noncontrolling interests $ 571 $ 45

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2020
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, (In millions, except per share amounts) 2020 2019 2018 Basic income per share attributable to NRG, Inc; Net income attributable to NRG Energy, Inc. common stockholders $ 510 $ 4,438 $ 268 Weighted average number of common shares outstanding-basic 245 262 304 Income per weighted average common share — basic $ 2.08 $ 16.94 $ 0.88 Diluted income per share attributable to NRG, Inc; Net income attributable to NRG Energy, Inc. common stockholders $ 510 $ 4,438 $ 268 Weighted average number of common shares outstanding-basic 245 262 304 Incremental shares attributable to the issuance of equity compensation (treasury stock method) 1 2 4 Weighted average number of common shares outstanding-diluted 246 264 308 Income per weighted average common share — diluted $ 2.07 $ 16.81 $ 0.87

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Segment Reporting	For the Year Ended December 31, 2020 (In millions) Texas East West/Other Corporate (a) Eliminations Total Operating revenues (a) $ 6,309 $ 2,354 $ 434 $ — $ (4) $ 9,093 Operating expenses 5,246 1,828 346 57 (4) 7,473 Depreciation and amortization 227 142 32 34 — 435 Impairment losses 14 — 61 — — 75 Development costs 4 3 1 — — 8 Total operating cost and expenses 5,491 1,973 440 91 (4) 7,991 (Loss)/gain on sale of assets — — (2) 5 — 3 Operating income/(loss) 818 381 (8) (86) — 1,105 Equity in (losses)/earnings of unconsolidated affiliates (12) — 29 — — 17 Impairment losses on investments (18) — — — — (18) Other income, net 11 7 8 41 — 67 Loss on debt extinguishment — (4) (5) — — (9) Interest expense — (14) (3) (384) — (401) Income/(loss) from continuing operations before income taxes 799 370 21 (429) — 761 Income tax (benefit)/expense — (1) 2 250 — 251 Net income/(loss) attributable to NRG Energy, Inc. $ 799 $ 371 $ 19 $ (679) $ — $ 510 Balance sheet Equity investments in affiliates $ (13) $ — $ 359 $ — $ — $ 346 Capital expenditures 130 45 30 25 — 230 Goodwill (b) 325 254 — — — 579 Total assets $ 7,641 $ 1,885 $ 1,584 $ 11,152 $ (7,360) $ 14,902 (a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues $ 6 $ (6) $ 4 $ — $ — $ 4 (b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach For the Year Ended December 31, 2019 (In millions) Texas East West/Other Corporate (a) Eliminations Total Operating revenues (a) $ 7,069 $ 2,319 $ 440 $ — $ (7) $ 9,821 Operating expenses 5,818 1,895 397 50 (7) 8,153 Depreciation and amortization 188 121 33 31 — 373 Impairment losses 1 — 4 — — 5 Development costs 3 3 1 — — 7 Total operating cost and expenses 6,010 2,019 435 81 (7) 8,538 Gain on sale of assets — 1 — 6 — 7 Operating income/(loss) 1,059 301 5 (75) — 1,290 Equity in (losses)/earnings of unconsolidated affiliates (4) — 6 — — 2 Impairment losses on investments (103) — — (5) — (108) Other income, net 20 6 10 30 — 66 Loss on debt extinguishment — — (3) (48) — (51) Interest expense — (18) (10) (385) — (413) Income/(loss) from continuing operations before income taxes 972 289 8 (483) — 786 Income tax expense/(benefit) — 2 1 (3,337) — (3,334) Net income from continuing operations 972 287 7 2,854 — 4,120 Gain from discontinued operations, net of income tax — — — 321 — 321 Net Income 972 287 7 3,175 — 4,441 Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests — — 3 — — 3 Net income attributable to NRG Energy, Inc. $ 972 $ 287 $ 4 $ 3,175 $ — $ 4,438 Balance sheet Equity investments in affiliates $ 6 $ — $ 382 $ — $ — $ 388 Capital expenditures 136 30 25 37 — 228 Goodwill (b) 325 254 — — — 579 Total assets $ 5,711 $ 2,160 $ 1,190 $ 8,342 $ (4,872) $ 12,531 (a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues $ 1 $ 8 $ (2) $ — $ — $ 7 (b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach For the Year Ended December 31, 2018 (In millions) Texas East West/Other Corporate (a) Eliminations Total Operating revenues (a) $ 6,401 $ 2,371 $ 724 $ — $ (18) $ 9,478 Operating expenses 5,399 2,024 467 125 (18) 7,997 Depreciation and amortization 156 105 127 33 — 421 Impairment losses 5 82 12 — — 99 Development costs 3 3 3 2 — 11 Total operating cost and expenses 5,563 2,214 609 160 (18) 8,528 Gain/(loss) on sale of assets 4 — (2) 30 — 32 Operating income/(loss) 842 157 113 (130) — 982 Equity in (losses)/earnings of unconsolidated affiliates (3) — 13 (1) — 9 Impairment losses on investments (15) — — — — (15) Other income/(loss), net 13 2 4 (1) — 18 Loss on debt extinguishment — — — (44) — (44) Interest expense — (22) (39) (422) — (483) Income/(loss) from continuing operations before income taxes 837 137 91 (598) — 467 Income tax expense — 1 — 6 — 7 Net income/(loss) from continuing operations 837 136 91 (604) — 460 Loss from discontinued operations, net of income tax — — — (192) — (192) Net Income/(loss) 837 136 91 (796) — 268 Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests — — 5 (5) — — Net income/(loss) attributable to NRG Energy, Inc. $ 837 $ 136 $ 86 $ (791) $ — $ 268 (a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues $ 19 $ (5) $ 4 $ — $ — $ 18 (b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
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, (In millions, except effective income tax rate) 2020 2019 2018 Current State $ 22 $ 2 $ 6 Foreign 4 4 — Total — current 26 6 6 Deferred U.S. Federal 168 (3,000) (16) State 60 (340) 16 Foreign (3) — 1 Total — deferred 225 (3,340) 1 Total income tax expense/(benefit) $ 251 $ (3,334) $ 7 Effective income tax rate 33.0 % (424.2) % 1.5 %
Domestic and foreign components of income/(loss) before income tax (benefit)/expense	The following represented the domestic and foreign components of income from continuing operations before income taxes: Year Ended December 31, (In millions) 2020 2019 2018 U.S. $ 749 $ 771 $ 468 Foreign 12 15 (1) Total $ 761 $ 786 $ 467
Reconciliation of the U.S. federal statutory rate to NRG's effective rate	Reconciliations of the U.S. federal statutory tax rate to NRG's effective tax rate were as follows: Year Ended December 31, (In millions, except effective income tax rate) 2020 2019 2018 Income from continuing operations before income taxes $ 761 $ 786 $ 467 Tax at federal statutory tax rate 160 165 98 State taxes 18 13 18 Permanent differences 8 (9) 7 Changes in valuation allowance 24 (3,492) (106) Deferred impact of state tax rate changes 2 12 — Production tax credits ("PTC") — — (7) Recognition of uncertain tax benefits 3 (10) 1 Return to provision adjustments 36 — — Alternative minimum tax ("AMT") refundable credit — — (4) Other — (13) — Income tax expense/(benefit) $ 251 $ (3,334) $ 7 Effective income tax rate 33.0 % (424.2) % 1.5 %
Company's deferred tax assets and liabilities	The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following: As of December 31, (In millions) 2020 2019 Deferred tax assets: Deferred compensation, accrued vacation and other reserves $ 79 $ 81 Difference between book and tax basis of property 357 548 Pension and other postretirement benefits 86 86 Equity compensation 10 11 Bad debt reserve 16 13 Derivatives, net 11 — U.S. Federal net operating loss carryforwards 2,117 2,116 Foreign net operating loss carryforwards 102 105 State net operating loss carryforwards 351 360 Federal and state tax credit carryforwards 384 384 Federal benefit on state uncertain tax positions 4 4 Interest disallowance carryforward per §163(j) of the Tax Act 4 82 Inventory obsolescence 6 7 Other 10 3 Total deferred tax assets 3,537 3,800 Deferred tax liabilities: Emissions allowances 21 19 Derivatives, net — 27 Goodwill 29 8 Intangibles amortization (excluding goodwill) 2 15 Equity method investments 156 201 Convertible Debt 16 19 Total deferred tax liabilities 224 289 Total deferred tax assets less deferred tax liabilities 3,313 3,511 Valuation allowance (266) (242) Total net deferred tax assets, net of valuation allowance $ 3,047 $ 3,269
Summary of NRG's net deferred tax position	The following table summarizes NRG's net deferred tax position as presented in the consolidated balance sheets: As of December 31, (In millions) 2020 2019 Deferred tax asset $ 3,066 $ 3,286 Deferred tax liability (19) (17) Net deferred tax asset $ 3,047 $ 3,269
Reconciliation of total amounts of uncertain tax benefits	The following table summarizes uncertain tax benefits activity: As of December 31, (In millions) 2020 2019 Balance as of January 1 $ 15 $ 26 Increase due to current year positions 3 2 Settlements, payments and statute closure (3) (13) Uncertain tax benefits as of December 31 $ 15 $ 15

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement, Noncash Expense [Abstract]
Summary of Company's non-vested RSU awards and changes during the year	The following table summarizes the Company's non-vested RSU awards and changes during the year: Units Weighted Average Grant Date Fair Value per Unit Non-vested at December 31, 2019 717,239 $ 25.56 Granted 271,718 38.05 Forfeited (16,750) 35.86 Vested (452,693) 20.73 Non-vested at December 31, 2020 519,514 35.87
Summary of Company's DSU awards and non-vested PSU Awards changes during the year	The following table summarizes the Company's outstanding DSU awards and changes during the year: Units Weighted Average Grant Date Fair Value per Unit Outstanding at December 31, 2019 331,223 $ 23.98 Granted 58,861 35.59 Converted to Common Stock (47,378) 26.87 Outstanding at December 31, 2020 342,706 25.37 The following table summarizes the Company's non-vested PSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit Non-vested at December 31, 2019 1,200,541 $ 26.65 Granted (a) 928,215 23.75 Forfeited (5,142) 35.77 Vested (b) (1,330,053) 15.91 Non-vested at December 31, 2020 (c) 793,561 41.69 (a) The weighted average grant date fair value per unit includes RPSUs that were granted during 2020 with grant date fair value of $45.60. It also includes RPSUs with 2017 grant date fair value of $15.91 and MSUs with 2016 grant date fair value of $15.28, that due to vesting at 200%, were considered additional grants in 2020 (b) MSUs granted during 2016 and RPSUs granted during 2017 vested during 2020 at 200% (c) Non-vested units as of December 31, 2020 includes 4,260 MSUs which were vested as of March 1, 2021
Schedule of Assumptions used in Fair Value Model	Significant assumptions used in the fair value model with respect to the Company's PSUs are summarized below: 2020 2019 2018 2017 2016 RPSUs RPSUs RPSUs RPSUs MSUs Expected volatility 30.15 % 40.72 % 47.52 % 43.96 % 34.33 % Expected term (in years) 3 3 3 3 3 Risk free rate 1.58 % 2.45 % 2.01 % 1.5 % 1.31 %
Summary of Company's NQSO activity, and changes during the year	The following table summarizes the Company's NQSO activity and changes during the year: Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in millions) Outstanding at December 31, 2019 134,398 $ 25.31 1 $ 2 Expired (9,083) 37.44 Exercised (48,268) 23.33 Outstanding at December 31, 2020 77,047 25.13 0.5 1 Exercisable at December 31, 2020 77,047 25.13 0.5 1
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, (In millions) 2020 2019 2018 Total intrinsic value of options exercised $ 1 $ 2 $ 10 Cash received from options exercised 1 3 24
Summary of NRG's total compensation expense recognized and total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized	The following table summarizes NRG's total compensation expense recognized for the years presented, as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2020, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $27 million, $36 million, and $19 million for the years ended December 31, 2020, 2019, and 2018, respectively, are reflected as a reduction to additional paid-in capital on the Company's consolidated balance sheets. Non-vested Compensation Cost (In millions, except weighted average data) Compensation Expense Unrecognized Total Cost Weighted Average Recognition Period Remaining (In years) Year Ended December 31, As of December 31, Award 2020 2019 2018 2020 2020 RSUs $ 9 $ 9 $ 12 $ 7 1.15 DSUs 2 2 2 — 0.00 MSUs — — 4 — 0.01 RPSUs 10 10 7 10 0.95 PRSUs (a) 6 11 16 6 1.24 Total $ 27 $ 32 $ 41 $ 23 Tax detriment recognized $ (9) $ (12) $ (4) three

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Summary of NRG's material related-party transactions with affiliates	The following table summarizes NRG's material related party transactions with third party affiliates: Year Ended December 31, (In millions) 2020 2019 2018 Revenues from Related Parties Included in Operating Revenues Gladstone $ 4 $ 4 $ 3 GenConn (a) — — 4 Ivanpah (b) 43 35 20 Midway-Sunset 5 5 5 Total $ 52 $ 44 $ 32 (a) As of August 31, 2018, NRG no longer had an ownership interest in GenConn as a result of the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform (b) Includes fees under project management agreements with each project company. Ivanpah became a related party to NRG upon deconsolidation in the second quarter of 2018

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments under coal, gas and transportation contractual agreements	As of December 31, 2020, the Company's minimum commitments under such outstanding agreements are estimated as follows: Period (In millions) 2021 $ 146 2022 98 2023 69 2024 67 2025 65 Thereafter 80 Total (a) $ 525
Minimum purchase commitment obligations under purchased power agreements	These contracts are not included in the consolidated balance sheet as of December 31, 2020. Minimum purchase commitment obligations are as follows as of December 31, 2020: Period (In millions) 2021 $ 48 2022 62 2023 50 2024 50 2025 49 Thereafter 316 Total (a) $ 575

Cash Flow Information (Tables)

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2020
Supplemental Cash Flow Information [Abstract]
Details of supplemental disclosures of cash flow and non-cash investing and financing information	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, (In millions) 2020 2019 2018 Cash and cash equivalents $ 3,905 $ 345 $ 563 Funds deposited by counterparties 19 32 33 Restricted cash 6 8 17 Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows $ 3,930 $ 385 $ 613 Detail of supplemental disclosures of cash flow and non-cash investing and financing information was: Year Ended December 31, (In millions) 2020 2019 2018 Interest paid, net of amount capitalized $ 340 $ 372 $ 436 Income taxes paid, net of refunds 24 8 9 Non-cash investing activities: (Decreases)/additions to fixed assets for accrued capital expenditures (6) 1 20

Guarantees (Tables)

Guarantees (Tables)	12 Months Ended
	Dec. 31, 2020
Guarantees [Abstract]
Summary of maximum potential exposure that can be estimated by NRG's 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, (In millions) 2020 Guarantees Under 1 Year 1-3 Years 3-5 Years Over 5 Years Total 2019 Total Letters of credit and surety bonds $ 1,049 $ 73 $ 31 $ — $ 1,153 $ 1,024 Asset sales guarantee obligations 86 282 26 112 506 698 Other guarantees — — — 87 87 288 Total guarantees $ 1,135 $ 355 $ 57 $ 199 $ 1,746 $ 2,010

Jointly Owned Plants (Tables)

Jointly Owned Plants (Tables)	12 Months Ended
	Dec. 31, 2020
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: (In millions unless otherwise stated) As of December 31, 2020 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress South Texas Project Units 1 and 2, Bay City, TX 44.00 % $ 428 $ (227) $ 1 Cedar Bayou Unit 4, Baytown, TX 50.00 % 220 (101) 9

SCHEDULE II - VALUATION AND Q_2

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Tables)	12 Months Ended
	Dec. 31, 2020
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS	(In millions) Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Deductions Balance at End of Period Allowance for credit losses, deducted from accounts receivable Year Ended December 31, 2020 $ 43 $ 108 $ — $ (84) (a) $ 67 Year Ended December 31, 2019 32 95 — (84) (a) 43 Year Ended December 31, 2018 28 83 — (79) (a) 32 Income tax valuation allowance, deducted from deferred tax assets Year Ended December 31, 2020 $ 242 $ 24 $ — $ — $ 266 Year Ended December 31, 2019 3,794 (3,543) (9) — 242 Year Ended December 31, 2018 1,863 1,934 (128) 125 (b) 3,794 (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

Nature of Business (Details)

Nature of Business (Details) MW in Thousands, customer in Millions	Jan. 05, 2021statecustomerprovince	Dec. 31, 2020MW	Aug. 01, 2019state
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Generation capacity (in MW) | MW		23
Business Acquisition [Line Items]
Number of states in which the entity operates | state			9
Subsequent Event
Business Acquisition [Line Items]
Customers served (over) | customer	6
Direct Energy | Subsequent Event
Business Acquisition [Line Items]
Customers served (over) | customer	3
Direct Energy | U.S. | Subsequent Event
Business Acquisition [Line Items]
Number of states in which the entity operates | state	50
Direct Energy | Canada | Subsequent Event
Business Acquisition [Line Items]
Provinces in which entity operates | province	8

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Net Income/(Loss) Attributable to Continuing and Discontinued Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Income from continuing operations, net of income tax	$ 510	$ 4,117	$ 465
Income/(loss) from discontinued operations, net of income tax	0	321	(197)
Net Income Attributable to NRG Energy, Inc.	$ 510	$ 4,438	$ 268

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Additional (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Funds Deposited by Counterparties
Number of months beyond which company can not predict the holding of collateral (in months)	12 months
Project Development Costs and Capitalized Interest
Amount of interest capitalized	$ 2	$ 3	$ 7
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, accumulated amortization	$ 1,357	1,262
Lease Revenue
Lease term	20 years
Lessor Accounting
Operating lease income	$ 18	20	21
Contingent rental income			104
Gross Receipts and Sales Taxes
Gross Receipts Tax	107	109	99
Purchased Energy and Other Cost of Sales for Customer Operations
Transmission and distribution charges not yet billed	98	103	105
Foreign Currency Translation and Transaction Gains and Losses
Cumulative translation adjustment	(2)	(13)	(13)
Marketing and Advertising Costs
Advertising expense	74	66	73
Reorganization Costs
Reorganization costs	$ 0	$ 23	$ 90
South Texas Project
Property, Plant and Equipment
Ownership Interest (as a percent)	44.00%

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Activity in the Allowance for Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 43
Provision for credit losses	108	$ 95	$ 85
Write-offs	(101)
Recoveries collected	17
Ending balance	$ 67	$ 43

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Cash and cash equivalents	$ 3,905	$ 345	$ 563
Funds deposited by counterparties	19	32	33
Restricted cash	6	8	17
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$ 3,930	$ 385	$ 613	$ 1,086

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Redeemable Non Controlling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Noncontrolling Interest [Roll Forward]
Balance at beginning of period	$ 20	$ 19	$ 78
Distributions to redeemable noncontrolling interest			(43)
Contributions from redeemable noncontrolling interest			26
Net income attributable to redeemable noncontrolling interest - continuing operations		3	1
Net loss attributable to redeemable noncontrolling interest - discontinued operations			(27)
Sale of NRG Yield and the Renewables Platform			(2,548)
Repurchase of redeemable noncontrolling interest	(20)
Balance at end of period	$ 0	20	19
NRG Yield Inc. And Zephyr Renewables
Noncontrolling Interest [Roll Forward]
Sale of NRG Yield and the Renewables Platform			(48)
Redeemable noncontrolling interest
Noncontrolling Interest [Roll Forward]
Distributions to redeemable noncontrolling interest		$ (2)	(3)
Non-cash adjustments to redeemable noncontrolling interest			$ (8)

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Accumulated deficit	$ (1,403)	$ (1,616)
Difference between Revenue Guidance in Effect before and after Topic 606 | Cumulative Effect, Period of Adoption, Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Accumulated deficit			$ 15

Revenue Recognition - Capacity

Revenue Recognition - Capacity Revenue (Details) $ in Millions	Dec. 31, 2020USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue from Contract with Customer [Abstract]
Estimated future fixed fee performance obligation	$ 668
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue from Contract with Customer [Abstract]
Estimated future fixed fee performance obligation	$ 289
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue from Contract with Customer [Abstract]
Estimated future fixed fee performance obligation	$ 47
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue from Contract with Customer [Abstract]
Estimated future fixed fee performance obligation	$ 36
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue from Contract with Customer [Abstract]
Estimated future fixed fee performance obligation	$ 20
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, period	1 year

Revenue Recognition - Disaggreg

Revenue Recognition - Disaggregated Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 8,690	$ 7,991	$ 8,148
Mark-to-market for economic hedging activities	(119)	(20)	14
Revenues	9,093	9,821	9,478
Less: Lease revenue	18	20	21
Derivative revenue	(124)	0	31
Retail Revenue | Mass customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	6,331	6,254	5,591
Retail Revenue | Business Solutions customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,129	1,279	1,303
Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	7,460	7,533	6,894
Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	539	1,169	1,496
Derivative revenue	105	1,595	1,233
Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	680	700	825
Derivative revenue	156	109	137
Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	95	33	(130)
Derivative revenue	385	1,810	1,309
Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	319	386	393
Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	9,093	9,821	9,478
Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	29	73	69
Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(7)	(5)	(19)
Revenues	(4)	(7)	(18)
Less: Lease revenue	0	0	0
Corporate/Eliminations | Retail Revenue | Mass customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(2)	(3)	(1)
Corporate/Eliminations | Retail Revenue | Business Solutions customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0	0
Corporate/Eliminations | Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(2)	(3)	(1)
Corporate/Eliminations | Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(1)	0	13
Derivative revenue	(5)	(1)	14
Corporate/Eliminations | Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(1)	0	0
Derivative revenue	0	0	0
Corporate/Eliminations | Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	8	(1)	(13)
Derivative revenue	3	(2)	1
Corporate/Eliminations | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(8)	(3)	(17)
Corporate/Eliminations | Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	(4)	(7)	(18)
Corporate/Eliminations | Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	0	0	1
Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	6,279	5,507	5,304
Revenues	6,309	7,069	6,401
Less: Lease revenue	0	0	1
Texas | Operating Segments | Retail Revenue | Mass customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	5,027	5,027	4,618
Texas | Operating Segments | Retail Revenue | Business Solutions customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,034	1,205	1,238
Texas | Operating Segments | Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	6,061	6,232	5,856
Texas | Operating Segments | Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	24	529	371
Derivative revenue	0	1,459	1,131
Texas | Operating Segments | Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0	0
Derivative revenue	0	0	0
Texas | Operating Segments | Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	2	47	(77)
Derivative revenue	30	1,562	1,096
Texas | Operating Segments | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	222	261	251
Texas | Operating Segments | Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	6,309	7,069	6,401
Texas | Operating Segments | Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	28	56	42
Texas | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenues	(6)	(1)	(19)
East | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,039	2,135	2,160
Revenues	2,354	2,319	2,371
Less: Lease revenue	1	1	1
East | Operating Segments | Retail Revenue | Mass customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,306	1,230	974
East | Operating Segments | Retail Revenue | Business Solutions customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	95	74	65
East | Operating Segments | Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,401	1,304	1,039
East | Operating Segments | Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	183	322	546
Derivative revenue	67	98	90
East | Operating Segments | Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	620	664	746
Derivative revenue	156	109	137
East | Operating Segments | Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	88	(29)	(35)
Derivative revenue	314	183	210
East | Operating Segments | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	62	58	75
East | Operating Segments | Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	2,354	2,319	2,371
East | Operating Segments | Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	3	5	17
East | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenues	6	(8)	5
West/Other | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	379	354	703
Revenues	434	440	724
Less: Lease revenue	17	19	19
West/Other | Operating Segments | Retail Revenue | Mass customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0	0
West/Other | Operating Segments | Retail Revenue | Business Solutions customers
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0	0
West/Other | Operating Segments | Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	0	0
West/Other | Operating Segments | Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	333	318	566
Derivative revenue	43	39	(2)
West/Other | Operating Segments | Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	61	36	79
Derivative revenue	0	0	0
West/Other | Operating Segments | Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	(3)	16	(5)
Derivative revenue	38	67	2
West/Other | Operating Segments | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	43	70	84
West/Other | Operating Segments | Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	434	440	724
West/Other | Operating Segments | Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	(2)	12	9
West/Other | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenues	$ (4)	$ 2	$ (4)

Revenue Recognition - Contract

Revenue Recognition - Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule Of Contract Assets And Liabilities [Line Items]
Deferred customer acquisition costs	$ 113	$ 133
Accounts receivable, net	904	1,025
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	393	402
Deferred revenue	60	82
Deferred revenue from contract with customers	31	24
Revenue recognized	13	13
Accounts receivable, net - Contracts with customers
Schedule Of Contract Assets And Liabilities [Line Items]
Accounts receivable, net	866	1,002
Accounts receivable, net - Derivative instruments
Schedule Of Contract Assets And Liabilities [Line Items]
Accounts receivable, net	33	18
Accounts receivable, net - Affiliate
Schedule Of Contract Assets And Liabilities [Line Items]
Accounts receivable, net	$ 5	$ 5

Acquisitions, Discontinued Op_3

Acquisitions, Discontinued Operations and Dispositions - Acquisitions (Details) customer in Thousands, $ in Millions	Jan. 05, 2021USD ($)statecustomerprovince	Sep. 29, 2020USD ($)	Aug. 01, 2019USD ($)statecustomer	Jun. 01, 2018USD ($)customerstate	Dec. 31, 2020USD ($)customer	Dec. 31, 2020USD ($)customer	Dec. 31, 2019USD ($)customer	Dec. 31, 2018USD ($)customer
Business Acquisition [Line Items]
Number of states in which the entity operates | state			9
Acquisition costs						$ 17
Operating lease liability					$ 347	347
Leased Assets, Powerton facility and Units 7 and 8 of the Joliet facility
Business Acquisition [Line Items]
Lease expense							$ 14
Operating lease liability		$ 148
Powerton Facility And Units 7 And 8 Of The Joliet Facility
Business Acquisition [Line Items]
Payment for asset acquisition		$ 260
Direct Energy
Business Acquisition [Line Items]
Proceeds from issuance of long-term debt					$ 2,900
Stream Energy
Business Acquisition [Line Items]
Cash paid to acquire business			$ 329
Working capital adjustments			$ 29
Residential customer equivalents acquired | customer			600
Customers acquired | customer			450
XOOM Energy, LLC
Business Acquisition [Line Items]
Number of states in which the entity operates | state				19
Purchase price				$ 213
Working capital adjustments				$ 48
Residential customer equivalents acquired | customer				395
Customers acquired | customer				300
Small Book Acquisitions 2020
Business Acquisition [Line Items]
Purchase price						$ 22
Customers acquired | customer					56	56
Small Book Acquisitions 2019
Business Acquisition [Line Items]
Purchase price							17
Cash paid to acquire business							$ 13
Customers acquired | customer							72
Small Book Acquisitions 2018
Business Acquisition [Line Items]
Purchase price								$ 44
Cash paid to acquire business							$ 2	$ 40
Customers acquired | customer								115
Subsequent Event
Business Acquisition [Line Items]
Customers added (over) | customer	6,000
Subsequent Event | Direct Energy
Business Acquisition [Line Items]
Customers added (over) | customer	3,000
Purchase price	$ 3,625
Purchase price adjustment	77
Cash paid to acquire business	715
Proceeds from revolving Credit Facility	166
Acquisition costs	$ 107
Subsequent Event | Direct Energy | U.S.
Business Acquisition [Line Items]
Number of states in which the entity operates | state	50
Subsequent Event | Direct Energy | Canada
Business Acquisition [Line Items]
Provinces in which entity operates | province	8

Acquisitions, Discontinued Op_4

Acquisitions, Discontinued Operations and Dispositions -Collective Collateral Facilities (Details) - USD ($) $ in Millions	Jan. 05, 2021	Dec. 31, 2020
Revolving Credit Facility | Revolving Credit Facility commitment increase
Line of Credit Facility [Line Items]
Revolving credit facility commitment increase		$ 802
Revolving Credit Facility | Revolving Credit Facility new tranche
Line of Credit Facility [Line Items]
Revolving credit facilities		273
Revolving Credit Facility | Credit default swap facility
Line of Credit Facility [Line Items]
Revolving credit facilities		150
Revolving Credit Facility | Revolving accounts receivable financing facility
Line of Credit Facility [Line Items]
Revolving credit facilities		750
Revolving Credit Facility | Repurchase facility
Line of Credit Facility [Line Items]
Revolving credit facilities		75
Revolving Credit Facility | Facility agreement in connection with sale of pre-capitalized trust securities
Line of Credit Facility [Line Items]
Revolving credit facilities		874
Revolving Credit Facility | Bilateral letter of credit facilities
Line of Credit Facility [Line Items]
Revolving credit facilities		475
Revolving Credit Facility | Total Increases to Liquidity and Collateral Facilities
Line of Credit Facility [Line Items]
Revolving credit facility commitment increase		$ 3,399
Subsequent Event | Direct Energy
Line of Credit Facility [Line Items]
Revolving credit facility commitment increase	$ 3,400

Acquisitions, Discontinued Op_5

Acquisitions, Discontinued Operations and Dispositions -Direct Energy Purchase Price Allocation (Details) - Direct Energy - Subsequent Event $ in Millions	Jan. 05, 2021USD ($)
Assets
Cash and cash equivalents	$ 152
Current assets	3,374
Property, plant and equipment	166
Goodwill and other intangible assets	3,446
Other non-current assets	687
Total assets acquired	7,825
Liabilities
Current liabilities	3,085
Non-current liabilities	1,038
Total liabilities assumed	4,123
Direct Energy Purchase Price	$ 3,702

Acquisitions, Discontinued Op_6

Acquisitions, Discontinued Operations and Dispositions - Purchase Price Allocation (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Aug. 01, 2019	Jun. 01, 2018
Business Acquisition [Line Items]
Goodwill	$ 579	$ 579
Stream Energy
Business Acquisition [Line Items]
Account receivable			$ 98
Accounts payable			(73)
Other net current and non-current working capital			5
Goodwill			6
Direct Energy Purchase Price			329
Stream Energy | Texas
Business Acquisition [Line Items]
Goodwill			5
Stream Energy | East
Business Acquisition [Line Items]
Goodwill			1
Stream Energy | Marketing Partnerships
Business Acquisition [Line Items]
Other intangible assets			154
Stream Energy | Customer Relationships
Business Acquisition [Line Items]
Other intangible assets			85
Stream Energy | Trade Names
Business Acquisition [Line Items]
Other intangible assets			28
Stream Energy | Other Intangible Assets
Business Acquisition [Line Items]
Other intangible assets			$ 26
XOOM Energy, LLC
Business Acquisition [Line Items]
Other net current and non-current working capital				$ 46
Other intangible assets				133
Goodwill				34
Direct Energy Purchase Price				213
XOOM Energy, LLC | Texas
Business Acquisition [Line Items]
Goodwill				28
XOOM Energy, LLC | East
Business Acquisition [Line Items]
Goodwill				$ 6

Acquisitions, Discontinued Op_7

Acquisitions, Discontinued Operations and Dispositions - Discontinued Operations (Details) $ in Millions	Feb. 06, 2018USD ($)extension	Dec. 31, 2020USD ($)MW	Dec. 31, 2019USD ($)	Feb. 04, 2019USD ($)MW	Aug. 31, 2018USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) | MW		23,000
Discontinued Operations | South Central Portfolio
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration				$ 1,000
Generation capacity (in MW) | MW				1,153
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
Discontinued Operations | NRG Yield Inc. And Zephyr Renewables | Cost To Complete Construction
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other commitment			$ 15
Discontinued Operations | NRG Yield Inc. And Zephyr Renewables | Property Taxes For Solar Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other commitment			22
Discontinued Operations | Carlsbad Energy Holdings LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration	$ 385
Other commitment		$ 23	$ 23
Membership percentage	100.00%
Lease and easement agreement, number of extensions | extension	2
Renewal term	10 years

Acquisitions, Discontinued Op_8

Acquisitions, Discontinued Operations and Dispositions - Summary of Results (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain/(loss) on disposal of discontinued operations, net of tax	$ 0	$ 0	$ (13)
Income/(loss) from discontinued operations, net of income tax	$ 0	321	(192)
Discontinued Operations | South Central Portfolio
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue		31	410
Operating costs and expenses		(23)	(346)
Other income		0	2
(Loss)/gain from operations of discontinued components, before tax		8	66
(Loss)/income on disposal of discontinued operations, net of tax		20	0
Income/(loss) from discontinued operations, net of income tax		28	66
Discontinued Operations | Carlsbad Energy Holdings LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue		19	909
Operating costs and expenses		(9)	(661)
Other expenses		(5)	(174)
(Loss)/gain from operations of discontinued components, before tax		5	74
Income tax expense		0	4
Income/(loss) from discontinued operations, net of tax		5	70
Gain/(loss) on disposal of discontinued operations, net of tax		265	(134)
Income/(expense) from California property tax indemnification		22	(153)
Income/(expense) from other commitments, indemnification and fees		4	(75)
(Loss)/income on disposal of discontinued operations, net of tax		291	(362)
Income/(loss) from discontinued operations, net of income tax		296	(292)
Discontinued Operations | GenOn
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest income-affiliate		0	3
Income/(loss) from discontinued operations, net of tax		0	3
Settlement consideration, insurance and services credit		0	63
Pension and post-retirement liability assumptions		0	21
Income/(expense) from other commitments, indemnification and fees		(3)	(53)
(Loss)/income on disposal of discontinued operations, net of tax		(3)	31
Income/(loss) from discontinued operations, net of income tax		$ (3)	$ 34

Acquisitions, Discontinued Op_9

Acquisitions, Discontinued Operations and Dispositions - Sale of Assets Prior to Discontinued (Details) $ in Millions	Dec. 31, 2020MW	Jan. 31, 2019USD ($)	Jun. 19, 2018USD ($)	Mar. 30, 2018USD ($)MW
Business Acquisition [Line Items]
Generation capacity (in MW) | MW	23,000
UPMC Thermal Project
Business Acquisition [Line Items]
Cash consideration		$ 3	$ 84
Buckthorn Renewables, LLC
Business Acquisition [Line Items]
Cash consideration				$ 42
Percentage of ownership sold				10000.00%
Generation capacity (in MW) | MW				154
Debt assumed				$ 183

Acquisitions, Discontinued O_10

Acquisitions, Discontinued Operations and Dispositions - GenOn Settlement and Plan Confirmation (Details) - USD ($) $ in Millions	Jul. 16, 2018	Apr. 27, 2018	Dec. 14, 2018
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		$ 38
Services Agreement | GenOn | Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Collateral posted	$ 15
GenOn
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Settlement consideration	261
Deduction for GenOn tax losses			$ 9,500
Professional fees		$ 6
GenOn | Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Settlement payment	125
GenOn | Services Agreement | Restructuring Support Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Credit applied	28
Remaining payments and other balances due under settlement agreement	10
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
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
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
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
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

Acquisitions, Discontinued O_11

Acquisitions, Discontinued Operations and Dispositions - Dispositions (Details) $ in Millions	Nov. 13, 2020USD ($)	Aug. 01, 2018USD ($)	Jun. 29, 2018USD ($)	Jun. 28, 2018USD ($)	Dec. 31, 2021USD ($)MW	Dec. 31, 2020USD ($)MW	Sep. 30, 2020USD ($)	Dec. 31, 2020USD ($)MW	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Nov. 19, 2020USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) | MW						23,000		23,000
Loss on debt extinguishment, net								$ (9)	$ (51)	$ (44)
Parent guarantee						$ 1,746		1,746	2,010
Home Solar
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale						66
Other guarantees
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Parent guarantee						$ 87		87	288
Agua Caliente Solar Project | 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											35.00%
Cash consideration											$ 202
Home Solar
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment loss							$ 29
Home Solar | 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	$ 66
(Loss) gain on sale of business	(2)
Debt extinguished	27
Loss on debt extinguishment, net	$ 5
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%
(Loss) gain on sale of business		$ 15
Proceeds from sale of businesses, net of working capital adjustments		71
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]
Proceeds from sale			$ 16
(Loss) gain on sale of business			$ 17
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]
Proceeds from sale								$ 15	$ 22
Subsequent Event | Scenario, Forecast | East/West Other
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) | MW					4,850
Proceeds from sale					$ 760
Subsequent Event | Scenario, Forecast | East/West Other | Arthur Kill Plant
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) | MW					866

Fair Value of Financial Instr_3

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, 2020	Dec. 31, 2019
Liabilities
Long-term debt	$ 8,855	$ 6,042
Level 2
Debt, Long-term and Short-term, Combined Amount [Abstract]
Long-term debt, including current portion	9,446	6,388
Level 3
Debt, Long-term and Short-term, Combined Amount [Abstract]
Long-term debt, including current portion	0	116
Carrying Amount
Assets
Notes receivable	2	11
Liabilities
Long-term debt	8,781	5,956
Fair Value
Assets
Notes receivable	2	8
Liabilities
Long-term debt	$ 9,446	$ 6,504

Fair Value of Financial Instr_4

Fair Value of Financial Instruments - Assets and Liabilities Measured and Recorded at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	$ 25	$ 20
Other trust fund investments:
Other trust fund investments	1	1
Measured using net asset value practical expedient:
Total assets	1,745	1,993
Derivative liabilities:
Total liabilities	884	1,103
Commodity contracts
Derivative assets:
Derivative assets	821	1,170
Derivative liabilities:
Commodity contracts	884	1,103
Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	23	17
U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	70	68
Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	89	100
Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	36	29
Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	144	109
Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	434	388
Measured using net asset value practical expedient:
Equity contracts	8	8
Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	7	5
Equity securities-nuclear trust fund investments
Measured using net asset value practical expedient:
Equity contracts	87	78
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	10	0
Other trust fund investments:
Other trust fund investments	1	1
Measured using net asset value practical expedient:
Total assets	597	558
Derivative liabilities:
Total liabilities	86	143
Level 1 | Commodity contracts
Derivative assets:
Derivative assets	59	84
Derivative liabilities:
Commodity contracts	86	143
Level 1 | Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	23	17
Level 1 | U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	69	68
Level 1 | Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 1 | Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 1 | Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 1 | Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	434	388
Measured using net asset value practical expedient:
Equity contracts	0	0
Level 1 | Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	1	0
Level 1 | Equity securities-nuclear trust fund investments
Measured using net asset value practical expedient:
Equity contracts	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	15	20
Other trust fund investments:
Other trust fund investments	0	0
Measured using net asset value practical expedient:
Total assets	914	1,156
Derivative liabilities:
Total liabilities	643	805
Level 2 | Commodity contracts
Derivative assets:
Derivative assets	623	893
Derivative liabilities:
Commodity contracts	643	805
Level 2 | Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 2 | U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	1	0
Level 2 | Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	89	100
Level 2 | Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	36	29
Level 2 | Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	144	109
Level 2 | Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Measured using net asset value practical expedient:
Equity contracts	0	0
Level 2 | Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	6	5
Level 2 | Equity securities-nuclear trust fund investments
Measured using net asset value practical expedient:
Equity contracts	0	0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	0	0
Other trust fund investments:
Other trust fund investments	0	0
Measured using net asset value practical expedient:
Total assets	139	193
Derivative liabilities:
Total liabilities	155	155
Level 3 | Commodity contracts
Derivative assets:
Derivative assets	139	193
Derivative liabilities:
Commodity contracts	155	155
Level 3 | Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Measured using net asset value practical expedient:
Equity contracts	0	0
Level 3 | Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Equity securities-nuclear trust fund investments
Measured using net asset value practical expedient:
Equity contracts	$ 0	$ 0

Fair Value of Financial Instr_5

Fair Value of Financial Instruments - Reconciliation of Level 3 Financial Instruments (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 38	$ 39
Contracts added from acquisitions		(3)
Total (losses) — realized/unrealized:
Total (losses) — realized/unrealized included in earnings		(26)
Purchases		40
Sale		(19)
Transfers into Level 3		2
Transfers out of Level 3		5
Ending balance		38
Gains 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
Debt Securities
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	0	19
Contracts added from acquisitions		0
Total (losses) — realized/unrealized:
Total (losses) — realized/unrealized included in earnings		0
Purchases		0
Sale		(19)
Transfers into Level 3		0
Transfers out of Level 3		0
Ending balance		0
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held at the end of period		0
Derivative
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	38	20
Contracts added from acquisitions		(3)
Total (losses) — realized/unrealized:
Total (losses) — realized/unrealized included in earnings	(44)	(26)
Purchases	(13)	40
Sale		0
Transfers into Level 3	1	2
Transfers out of Level 3	2	5
Ending balance	(16)	38
Gains 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	$ 9	$ 17

Fair Value of Financial Instr_6

Fair Value of Financial Instruments - Derivative Fair Value Measurements Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
Fair Value Disclosures [Abstract]
Total derivative assets valued with prices provided by models and other valuation techniques percentage	17.00%
Total derivative liabilities valued with prices provided by models and other valuation techniques, percentage	18.00%
Increase In credit reserve, primarily in cost of operations	$ 2

Fair Value of Financial Instr_7

Fair Value of Financial Instruments - Derivative Fair Value Measurement (Details) $ in Millions	Dec. 31, 2020USD ($)$ / MWh	Dec. 31, 2019USD ($)$ / MWh
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Cash collateral posted in support of energy risk management activities	$ 50	$ 190
Cash collateral received in support of energy risk management activities	19	32
Commodity contracts
Assets
Derivative assets	821	1,170
Liabilities
Commodity contracts	884	1,103
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Cash collateral posted in support of energy risk management activities	0	73
Cash collateral received in support of energy risk management activities	5	7
Commodity contracts | Level 3
Assets
Derivative assets	139	193
Liabilities
Commodity contracts	155	155
Commodity contracts | Fair Value, Measurements, Recurring | Level 3
Assets
Derivative assets	139	193
Liabilities
Commodity contracts	155	155
Commodity contracts | Fair Value, Measurements, Recurring | Power Contracts | Level 3
Assets
Derivative assets	111	151
Liabilities
Commodity contracts	$ 143	$ 139
Commodity contracts | Fair Value, Measurements, Recurring | Power Contracts | Level 3 | Low
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Forward Market Price (USD per MWh) | $ / MWh	10	8
Commodity contracts | Fair Value, Measurements, Recurring | Power Contracts | Level 3 | High
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Forward Market Price (USD per MWh) | $ / MWh	105	218
Commodity contracts | Fair Value, Measurements, Recurring | Power Contracts | Level 3 | Weighted Average
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Forward Market Price (USD per MWh) | $ / MWh	21	24
Commodity contracts | Fair Value, Measurements, Recurring | Financial Transmission Rights | Level 3
Assets
Derivative assets	$ 28	$ 42
Liabilities
Commodity contracts	$ 12	$ 16
Commodity contracts | Fair Value, Measurements, Recurring | Financial Transmission Rights | Level 3 | Low
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Auction Prices (USD per MWh) | $ / MWh	(28)	(105)
Commodity contracts | Fair Value, Measurements, Recurring | Financial Transmission Rights | Level 3 | High
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Auction Prices (USD per MWh) | $ / MWh	43	213
Commodity contracts | Fair Value, Measurements, Recurring | Financial Transmission Rights | Level 3 | Weighted Average
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Auction Prices (USD per MWh) | $ / MWh	0	0

Fair Value of Financial Instr_8

Fair Value of Financial Instruments - Counterparty Credit Risk (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)counterparty	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Derivative Fair Value Meaurements and Concentration of Credit Risk
Counterparty credit exposure, excluding credit risk exposure under certain long term agreements	$ 210
Counterparty credit exposure, collateral held (cash and letters of credit) against positions	14
Counterparty credit exposure, net	$ 204
Company's exposure before collateral expected to roll off (as a percent)	54.00%
Net exposure (as a percent)	100.00%
Wholesale counterparties with net exposure | counterparty	47,000,000
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	$ 645
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 credit losses	$ 108	$ 95	$ 85
Investment grade
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	59.00%
Non-Investment grade/Non-Rated
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	41.00%
Utilities, energy merchants, marketers and other
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	96.00%
Financial Institutions
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	4.00%

Accounting for Derivative Ins_3

Accounting for Derivative Instruments and Hedging Activities - Net Notional Volume Buy/Sell of Open Derivative Transactions (Details) shares in Millions, T in Millions, MWh in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2020MWhMMBTUTshares	Dec. 31, 2019MWhMMBTUTshares
Long | Emissions
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton) | T	1	3
Long | Renewables Energy Certificates
Derivative [Line Items]
Derivative, non-monetary notional amount (in shares) | shares	5	1
Long | Coal
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton) | T	2	10
Long | Power
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) | MWh	57	38
Short | Natural Gas
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) | MMBTU	286	181
Short | Capacity
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) | MWh	1	1

Accounting for Derivative Ins_4

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, 2020	Dec. 31, 2019
Derivative [Line Items]
Derivative assets	$ 821	$ 1,170
Commodity contracts	884	1,103
Commodity contracts current
Derivative [Line Items]
Derivative assets	560	860
Commodity contracts	499	781
Commodity contracts long-term
Derivative [Line Items]
Derivative assets	261	310
Commodity contracts	$ 385	$ 322

Accounting for Derivative Ins_5

Accounting for Derivative Instruments and Hedging Activities - Offsetting of Derivatives by Counterparty Master Agreement level and Collateral Received (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Cash Collateral (Held)/Posted	$ (19)	$ (32)
Cash Collateral (Held)/Posted	50	190
Commodity contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	821	1,170
Derivative Instruments	(658)	(909)
Cash Collateral (Held)/Posted	(5)	(7)
Net Amount	158	254
Derivative liabilities	(884)	(1,103)
Derivative Instruments	658	909
Cash Collateral (Held)/Posted	0	73
Net Amount	(226)	(121)
Gross Amounts of Recognized Assets / Liabilities	(63)	67
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	(5)	66
Net Amount	$ (68)	$ 133

Accounting for Derivative Ins_6

Accounting for Derivative Instruments and Hedging Activities - Effect on Accumulated OCI Balance Attributable to Cash Flow Hedge Derivatives, Net (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income [Roll Forward]
Beginning balance	$ 1,968
Sale of NRG Yield and Renewables	25
Ending balance	(1,234)
Interest rate contracts | AOCI Including Portion Attributable to Noncontrolling Interest
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income [Roll Forward]
Beginning balance	(54)
Ending balance	0
Interest rate contracts | Accumulated Gain (Loss), Net, Cash Flow Hedge, Parent
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income [Roll Forward]
Due to realization of previously deferred amounts	8
Interest rate contracts | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income [Roll Forward]
Mark-to-market of cash flow hedge accounting contracts	$ 21

Accounting for Derivative Ins_7

Accounting for Derivative Instruments and Hedging Activities - Narrative (Details) - Interest Rate Contract $ in Millions	3 Months Ended
	Dec. 31, 2020USD ($)
Derivative [Line Items]
Interest rate hedge	$ 1,600
Gain on derivative	$ 11

Accounting for Derivative Ins_8

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Unrealized Mark To Market Results [Abstract]
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$ (55)	$ (68)	$ (73)
Reversal of acquired loss/(gain) positions related to economic hedges	4	6	(10)
Net unrealized (losses)/gains on open positions related to economic hedges	68	(42)	(97)
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(119)	(20)	14
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity	(20)	(11)	(12)
Net unrealized gains on open positions related to trading activity	15	31	29
Total unrealized mark-to-market (losses)/gains for trading activity	(5)	20	17
Total unrealized (losses)/gains	(124)	0	31
Credit Risk Related Contingent Features [Abstract]
Collateral required contracts with credit rating contingent features in a net liability position	35
Additional collateral required	1
Adequate Assurance Clauses
Credit Risk Related Contingent Features [Abstract]
Collateral required for contracts in net liability positions that have adequate assurance clauses	26
Commodity contracts
Unrealized Mark To Market Results [Abstract]
Total unrealized (losses)/gains	(124)	0	31
Commodity contracts | Operating revenue
Unrealized Mark To Market Results [Abstract]
Total unrealized (losses)/gains	90	53	(113)
Commodity contracts | Cost of operations
Unrealized Mark To Market Results [Abstract]
Total unrealized (losses)/gains	(214)	(53)	144
Interest rate contracts
Unrealized Mark To Market Results [Abstract]
Total unrealized (losses)/gains	$ 0	$ (38)	$ 0

Nuclear Decommissioning Trust_3

Nuclear Decommissioning Trust Fund - Summary of Aggregate Fair Values and Realized Gains and Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Nuclear decommissioning trust fund disclosure
Fair Value	$ 890	$ 794
Unrealized Gains	398	338
Unrealized Losses	0	1
Cash and cash equivalents
Nuclear decommissioning trust fund disclosure
Fair Value	23	17
Unrealized Gains	0	0
Unrealized Losses	0	0
U.S. government and federal agency obligations
Nuclear decommissioning trust fund disclosure
Fair Value	70	68
Unrealized Gains	6	4
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	10 years	11 years
Federal agency mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 89	$ 100
Unrealized Gains	4	3
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	24 years	24 years
Commercial mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 36	$ 29
Unrealized Gains	2	1
Unrealized Losses	$ 0	$ 1
Weighted- average maturities (in years)	27 years	24 years
Corporate debt securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 144	$ 109
Unrealized Gains	13	6
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	12 years	11 years
Equity securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 521	$ 466
Unrealized Gains	372	324
Unrealized Losses	0	0
Foreign government fixed income securities
Nuclear decommissioning trust fund disclosure
Fair Value	7	5
Unrealized Gains	1	0
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	10 years	10 years
South Texas Project
Nuclear decommissioning trust fund disclosure
Ownership Interest (as a percent)	44.00%

Nuclear Decommissioning Trust_4

Nuclear Decommissioning Trust Fund - Summary of Proceeds from Sale of Available -for-sale Securities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Regulated Operations [Abstract]
Realized gains	$ 34	$ 18	$ 17
Realized (losses)	(13)	(9)	(13)
Proceeds from sales of nuclear decommissioning trust fund securities	$ 439	$ 381	$ 513

Inventory (Details)

Inventory (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Inventory Disclosure [Abstract]
Fuel oil	$ 37	$ 73
Coal	73	93
Natural gas	22	21
Spare parts	195	196
Total Inventory	327	383
Inventory [Line Items]
Inventory lower of cost or market adjustment	29	$ 0	$ 2
Fuel Oil
Inventory [Line Items]
Inventory lower of cost or market adjustment	$ 29

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment
Total property, plant, and equipment	$ 4,483	$ 4,345
Accumulated depreciation	(1,936)	(1,752)
Net property, plant, and equipment	2,547	2,593
Depreciation	295	271	$ 356
Facilities and equipment
Property, Plant and Equipment
Total property, plant, and equipment	$ 3,365	3,262
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	$ 329	324
Nuclear fuel
Property, Plant and Equipment
Total property, plant, and equipment	$ 239	235
Depreciable lives (in years)	5 years
Hardware and office equipment and furnishings
Property, Plant and Equipment
Total property, plant, and equipment	$ 453	422
Hardware and office equipment and furnishings | Minimum
Property, Plant and Equipment
Depreciable lives (in years)	2 years
Hardware and office equipment and furnishings | Maximum
Property, Plant and Equipment
Depreciable lives (in years)	10 years
Construction in progress
Property, Plant and Equipment
Total property, plant, and equipment	$ 97	$ 102

Leases - Lease Cost and Other I

Leases - Lease Cost and Other Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost [Abstract]
Finance lease cost	$ 3	$ 0
Operating lease cost	100	109
Short-term lease cost	3	3
Variable lease cost	6	6
Sublease income	(17)	(17)
Total lease cost	95	101
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	101	104
Financing cash flows from finance leases	1	0
Right-of-use assets obtained in exchange for new finance lease liabilities	5	0
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 4	$ 215
Finance leases:
Weighted average remaining lease term (in years)	1 year 1 month 6 days
Weighted average discount rate	4.79%
Operating Leases [Abstract]
Weighted average remaining lease term (in years)	5 years 3 months 18 days	7 years 9 months 18 days
Weighted average discount rate	5.63%	5.72%

Leases - Annual Payments Based

Leases - Annual Payments Based on the Maturities of Leases (Details) $ in Millions	Dec. 31, 2020USD ($)
Leases [Abstract]
2021	$ 86
2022	82
2023	81
2024	71
2025	47
Thereafter	34
Total undiscounted lease payments	401
Less present value adjustment	(54)
Operating lease liability	$ 347

Asset Impairments (Details)

Asset Impairments (Details) - USD ($)	Sep. 05, 2018	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Feb. 20, 2019
Asset Impairments
Impairment losses, other assets							$ 14,000,000	$ 12,000,000
Impairment losses							75,000,000	5,000,000	$ 99,000,000
Equity method investments							346,000,000	388,000,000
Impairment losses on investments							18,000,000	$ 108,000,000	15,000,000
Held-for-sale | NRG Solar Guam, LLC
Asset Impairments
Impairment losses					$ 12,000,000
Cash consideration										$ 8,000,000
Cottonwood | West/Other
Asset Impairments
Impairment losses on equity method investments							$ 32,000,000
Home Solar | West/Other
Asset Impairments
Impairment losses on equity method investments		$ 29,000,000
Petra Nova Parish Holdings
Asset Impairments
Impairment losses on equity method investments				$ 101,000,000
Letter of credit				12,000,000
Contribution in cash				95,000,000
Guarantee (up to)				$ 124,000,000
Ownership percentage							50.00%
Equity method investments							$ (13,000,000)
Petra Nova Parish Holdings | Texas
Asset Impairments
Impairment losses on equity method investments			$ 18,000,000
Keystone
Asset Impairments
Impairment losses on equity method investments	$ 14,000,000
Ownership percentage	3.70%
Conemaugh
Asset Impairments
Impairment losses on equity method investments	$ 14,000,000
Dunkirk
Asset Impairments
Impairment losses on equity method investments						$ 46,000,000
Equity method investments						$ 0
Other Investments
Asset Impairments
Impairment losses on equity method investments									15,000,000
Impairment losses on investments									$ 13,000,000

Goodwill and Other Intangible_2

Goodwill and Other Intangibles - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Goodwill and Other Intangibles
Goodwill	$ 579	$ 579
Held-for-sale
Goodwill and Other Intangibles
Emission allowances held-for-sale	14	$ 6
Midwest Generation
Goodwill and Other Intangibles
Goodwill	165
Retail Business Acquisitions
Goodwill and Other Intangibles
Goodwill	$ 414

Goodwill and Other Intangible_3

Goodwill and Other Intangibles - Components of Intangible Assets Subject to Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	$ 2,051	$ 1,742
Purchases	70	42
Acquisition of businesses	22	318
Usage/Retirements	(35)	(21)
Write-off of fully amortized balances	(74)	(30)
Impairment	(14)	(2)
Other	5	2
Balance at end of period	2,025	2,051
Less accumulated amortization	(1,357)	(1,262)
Net carrying amount	668	789
Renewables Energy Certificates
Finite-lived Intangible Assets [Roll Forward]
Carrying value	28	18
Emission Allowances
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	662	659
Purchases	25	13
Acquisition of businesses	0	0
Usage/Retirements	0	(4)
Write-off of fully amortized balances	(4)	(8)
Impairment	(14)	0
Other	3	2
Balance at end of period	672	662
Less accumulated amortization	(563)	(539)
Net carrying amount	109	123
Fuel Contracts
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	49	49
Purchases	0	0
Acquisition of businesses	0	0
Usage/Retirements	0	0
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	0
Balance at end of period	49	49
Less accumulated amortization	(46)	(45)
Net carrying amount	3	4
Customer Relationships
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	573	478
Purchases	0	0
Acquisition of businesses	22	110
Usage/Retirements	0	0
Write-off of fully amortized balances	(70)	(13)
Impairment	0	(2)
Other	2	0
Balance at end of period	527	573
Less accumulated amortization	(349)	(345)
Net carrying amount	$ 178	$ 228
Weighted average useful life, years	5 years	7 years
Marketing Partnerships
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	$ 285	$ 131
Purchases	0	0
Acquisition of businesses	0	154
Usage/Retirements	0	0
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	0
Balance at end of period	285	285
Less accumulated amortization	(99)	(75)
Net carrying amount	186	$ 210
Weighted average useful life, years		9 years
Trade Names
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	373	$ 345
Purchases	0	0
Acquisition of businesses	0	28
Usage/Retirements	0	0
Write-off of fully amortized balances	0	0
Impairment	0	0
Other	0	0
Balance at end of period	373	373
Less accumulated amortization	(247)	(220)
Net carrying amount	126	$ 153
Weighted average useful life, years		12 years
Other(b)
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	109	$ 80
Purchases	45	29
Acquisition of businesses	0	26
Usage/Retirements	(35)	(17)
Write-off of fully amortized balances	0	(9)
Impairment	0	0
Other	0	0
Balance at end of period	119	109
Less accumulated amortization	(53)	(38)
Net carrying amount	$ 66	$ 71
Energy Supply Contract
Finite-lived Intangible Assets [Roll Forward]
Weighted average useful life, years		2 years

Goodwill and Other Intangible_4

Goodwill and Other Intangibles - Schedule of Amortization and Retirement of Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Total amortization	$ 204	$ 151	$ 133
Depreciation and amortization	435	373	421
Renewables Energy Certificates | Cost of operations
Finite-Lived Intangible Assets [Line Items]
Finite-lived intangible asset retirements	36	17	28
Emission Allowances
Finite-Lived Intangible Assets [Line Items]
Total amortization	28	32	39
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total amortization	74	44	32
Marketing Partnerships
Finite-Lived Intangible Assets [Line Items]
Total amortization	24	15	9
Trade Names
Finite-Lived Intangible Assets [Line Items]
Total amortization	27	25	23
Other(b)
Finite-Lived Intangible Assets [Line Items]
Total amortization	51	35	30
Depreciation and amortization	$ 15	$ 18	$ 2

Goodwill and Other Intangible_5

Goodwill and Other Intangibles - Schedule of Estimated Amortization of Intangible Asset for the Next Five Years (Details) $ in Millions	Dec. 31, 2020USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2021	$ 149
2022	128
2023	127
2024	91
2025	70
Emission Allowances
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2021	31
2022	30
2023	30
2024	31
2025	29
Fuel Contracts
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2021	0
2022	1
2023	0
2024	1
2025	0
Customer Relationships
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2021	64
2022	44
2023	45
2024	16
2025	5
Marketing Partnerships
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2021	24
2022	23
2023	23
2024	23
2025	22
Trade Names
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2021	27
2022	27
2023	26
2024	17
2025	11
Other(b)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2021	3
2022	3
2023	3
2024	3
2025	$ 3

Receivables Securitization an_2

Receivables Securitization and Repurchase Facility (Details) - Secured Debt - USD ($)	Sep. 22, 2020	Dec. 31, 2020
Receivables Facility
Line of Credit Facility [Line Items]
Revolving credit facility	$ 750,000,000
Weighted average interest rate		0.537%
Borrowings outstanding		$ 0
Receivables Facility | Letter of Credit
Line of Credit Facility [Line Items]
Letter of credit		198,000,000
Repurchase Facility
Line of Credit Facility [Line Items]
Revolving credit facility	75,000,000
Borrowings outstanding		$ 0
Commitment fee	$ 0
Repurchase Facility | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate (as a percent)	1.25%

Long-term Debt and Finance Le_3

Long-term Debt and Finance Leases - Schedule of Long-term Debt and Finance Leases (Details) $ / shares in Units, $ in Millions	Jan. 29, 2021$ / shares	Dec. 31, 2020USD ($)$ / shares	Dec. 31, 2019USD ($)$ / shares	Dec. 02, 2020	Mar. 11, 2020	May 28, 2019	May 24, 2019	May 14, 2019	Dec. 07, 2017	Aug. 02, 2016	May 23, 2016
Debt Instrument [Line Items]
Long-term debt		$ 8,855	$ 6,042
Finance leases		4	0
Subtotal long-term debt and finance leases (including current maturities)		8,859	6,042
Less current maturities		(1)	(88)
Less debt issuance costs		(93)	(65)
Discounts		(74)	(86)
Total long-term debt and finance leases		8,691	5,803
Debt Instrument, Unamortized Discount [Abstract]
Total discounts		(74)	(86)
Recourse Debt
Debt Instrument [Line Items]
Long-term debt		8,855	6,008
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	1,230
Interest rate, stated percentage		6.625%								6.625%
Recourse Debt | Senior Notes, due 2028
Debt Instrument [Line Items]
Long-term debt		$ 821	821
Interest rate, stated percentage		5.75%							5.75%
Recourse Debt | Senior Notes, due 2029
Debt Instrument [Line Items]
Long-term debt		$ 733	733
Interest rate, stated percentage		5.25%					5.25%	5.25%
Recourse Debt | Senior Notes, due 2029
Debt Instrument [Line Items]
Long-term debt		$ 500	0
Interest rate, stated percentage		3.375%		3.375%
Recourse Debt | 3.625% Senior Unsecured Notes Due 2031 [Member]
Debt Instrument [Line Items]
Long-term debt		$ 1,030	0
Interest rate, stated percentage		3.625%		3.625%
Recourse Debt | Convertible Senior Notes Due 2048
Debt Instrument [Line Items]
Long-term debt		$ 575	575
Discounts		$ (72)	$ (85)
Interest rate, stated percentage		2.75%
Effective rate		5.19%	5.05%
Conversion price per common share (in usd per share) | $ / shares		$ 46.24	$ 47.74
Conversion ratio		0.0216242	0.0209479
Debt Instrument, Unamortized Discount [Abstract]
Total discounts		$ (72)	$ (85)
Recourse Debt | Convertible Senior Notes Due 2048 | Subsequent Event
Debt Instrument [Line Items]
Conversion price per common share (in usd per share) | $ / shares	$ 45.94
Conversion ratio	0.02177
Debt discount amortization period	4 years 8 months 12 days
Recourse Debt | Senior Secured First Lien Notes, due 2024
Debt Instrument [Line Items]
Long-term debt		$ 600	600
Interest rate, stated percentage		3.75%				2.75%
Recourse Debt | Senior Secured First Lien Notes, due 2025
Debt Instrument [Line Items]
Long-term debt		$ 500	0
Interest rate, stated percentage		2.00%		2.00%
Recourse Debt | Senior Secured First Lien Notes, due 2027
Debt Instrument [Line Items]
Long-term debt		$ 900	0
Interest rate, stated percentage		2.45%		2.45%
Recourse Debt | Senior Secured First Lien Notes, due 2029
Debt Instrument [Line Items]
Long-term debt		$ 500	500
Interest rate, stated percentage		4.45%				4.45%
Recourse Debt | Tax-exempt bonds
Debt Instrument [Line Items]
Long-term debt		$ 466	466
Recourse Debt | Tax-exempt bonds | Minimum
Debt Instrument [Line Items]
Interest rate, stated percentage		1.25%			1.30%
Recourse Debt | Tax-exempt bonds | Maximum
Debt Instrument [Line Items]
Interest rate, stated percentage		4.75%
Recourse Debt | Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029
Debt Instrument [Line Items]
Discounts		$ (2)	(1)
Debt Instrument, Unamortized Discount [Abstract]
Total discounts		(2)	(1)
Line of Credit | Revolving Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt		$ 0	83
Line of Credit | Revolving Credit Facility | Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		1.75%
Non Recourse Debt
Debt Instrument [Line Items]
Long-term debt		$ 0	34
Non Recourse Debt | Other
Debt Instrument [Line Items]
Long-term debt		$ 0	$ 34

Long-term Debt and Finance Le_4

Long-term Debt and Finance Leases - Annual Payments Based on the Maturities of Debt and Capital Leases (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
2021	$ 1
2022	2
2023	1
2024	600
2025	500
Thereafter	7,755
Subtotal long-term debt and finance leases (including current maturities)	$ 8,859	$ 6,042

Long-term Debt and Finance Le_5

Long-term Debt and Finance Leases - Issuance of Senior Notes (Details) - Recourse Debt - USD ($)	Dec. 02, 2020	Dec. 31, 2020	Dec. 31, 2019	May 28, 2019	May 24, 2019	May 14, 2019
3.375% Senior Notes Due 2029
Debt Instrument [Line Items]
Aggregate principal amount	$ 500,000,000
Interest rate, stated percentage	3.375%	3.375%
3.625% Senior Unsecured Notes Due 2031 [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 1,000,000,000
Interest rate, stated percentage	3.625%	3.625%
Senior Secured First Lien Notes due 2025 to 2027
Debt Instrument [Line Items]
Aggregate principal amount	$ 1,400,000,000
Basis point increase to interest rate	0.25%
Senior Secured First Lien Notes, due 2025
Debt Instrument [Line Items]
Aggregate principal amount	$ 500,000,000
Interest rate, stated percentage	2.00%	2.00%
Senior Secured First Lien Notes, due 2027
Debt Instrument [Line Items]
Aggregate principal amount	$ 900,000,000
Interest rate, stated percentage	2.45%	2.45%
5.25% Senior Notes due 2029
Debt Instrument [Line Items]
Aggregate principal amount						$ 733,000,000
Interest rate, stated percentage		5.25%			5.25%	5.25%
6.25% Senior Notes due 2024
Debt Instrument [Line Items]
Interest rate, stated percentage		6.25%	6.25%
Senior Secured First Lien Notes, Due 2024 and 2029
Debt Instrument [Line Items]
Aggregate principal amount				$ 1,100,000,000
Senior Secured First Lien Notes, Due 2024
Debt Instrument [Line Items]
Aggregate principal amount				$ 600,000,000
Interest rate, stated percentage		3.75%		2.75%
Senior Secured First Lien Notes, Due 2029
Debt Instrument [Line Items]
Aggregate principal amount				$ 500,000,000
Interest rate, stated percentage		4.45%		4.45%

Long-term Debt and Finance Le_6

Long-term Debt and Finance Leases - Senior Notes Redemption and Repurchases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Loss on debt extinguishment	$ 9	$ 51	$ 44
Recourse Debt | 6.25% Senior Notes due 2024
Debt Instrument [Line Items]
Cash Paid		$ 733
Interest rate, stated percentage	6.25%	6.25%
Loss on debt extinguishment		$ (29)
Write off of deferred debt issuance cost		$ 5

Long-term Debt and Finance Le_7

Long-term Debt and Finance Leases - Issuance of Convertible Senior Notes (Details) - Convertible Senior Notes Due 2048 - Recourse Debt $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)$ / shares	Dec. 31, 2019USD ($)$ / shares
Debt Instrument [Line Items]
Conversion price per common share (in usd per share) | $ / shares	$ 46.24	$ 47.74
Conversion ratio	0.0216242	0.0209479
Carrying amount of equity component | $	$ 503	$ 491

Long-term Debt and Finance Le_8

Long-term Debt and Finance Leases - Senior Notes Outstanding with Early Redemption Features (Details) - Recourse Debt	Dec. 31, 2020	Dec. 02, 2020	May 24, 2019	May 14, 2019	Dec. 07, 2017	Aug. 02, 2016	May 23, 2016
7.250% Senior Notes due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage	7.25%						7.25%
6.625% Senior Notes due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%					6.625%
5.750% Senior Notes due 2028
Debt Instrument [Line Items]
Interest rate, stated percentage	5.75%				5.75%
5.25% Senior Notes due 2029
Debt Instrument [Line Items]
Interest rate, stated percentage	5.25%		5.25%	5.25%
3.375% Senior Notes due 2029
Debt Instrument [Line Items]
Interest rate, stated percentage	3.375%	3.375%
3.625% Senior Notes due 2031
Debt Instrument [Line Items]
Interest rate, stated percentage		3.625%

Long-term Debt and Finance Le_9

Long-term Debt and Finance Leases - Recourse Debt Redemption Period (Details) - Recourse Debt	12 Months Ended
	Dec. 31, 2020	Dec. 02, 2020	May 24, 2019	May 14, 2019	Dec. 07, 2017	Aug. 02, 2016	May 23, 2016
Senior Notes
Debt Instrument [Line Items]
Redemption percentage of principal	25.00%
7.250% Senior Notes due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage	7.25%						7.25%
7.250% Senior Notes due 2026 | Redemption Period Prior To 15 May 2021
Debt Instrument [Line Items]
Redemption percentage	100.00%
Present value of note (as percentage)	1.03625
7.250% Senior Notes due 2026 | May 15, 2021 to May 14, 2022
Debt Instrument [Line Items]
Redemption percentage	103.625%
7.250% Senior Notes due 2026 | May 15, 2022 to May 14, 2023
Debt Instrument [Line Items]
Redemption percentage	102.417%
7.250% Senior Notes due 2026 | May 15, 2023 to May 14, 2024
Debt Instrument [Line Items]
Redemption percentage	101.208%
7.250% Senior Notes due 2026 | May 15, 2024 and thereafter
Debt Instrument [Line Items]
Redemption percentage	100.00%
7.250% Senior Notes due 2026 | Treasury Rate
Debt Instrument [Line Items]
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Treasury rate redemption (as percentage)	0.50%
6.625% Senior Notes due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%					6.625%
6.625% Senior Notes due 2027 | Redemption Period Prior To 15 July 2021
Debt Instrument [Line Items]
Redemption percentage	100.00%
Present value of note (as percentage)	1.03313
6.625% Senior Notes due 2027 | July 15, 2021 to July 14, 2022
Debt Instrument [Line Items]
Redemption percentage	103.313%
6.625% Senior Notes due 2027 | July 15, 2022 to July 14, 2023
Debt Instrument [Line Items]
Redemption percentage	102.208%
6.625% Senior Notes due 2027 | July 15, 2023 to July 14, 2024
Debt Instrument [Line Items]
Redemption percentage	101.104%
6.625% Senior Notes due 2027 | July 15, 2024 and thereafter
Debt Instrument [Line Items]
Redemption percentage	100.00%
6.625% Senior Notes due 2027 | Treasury Rate
Debt Instrument [Line Items]
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Treasury rate redemption (as percentage)	50.00%
5.750% Senior Notes due 2028
Debt Instrument [Line Items]
Redemption percentage	35.00%
Interest rate, stated percentage	5.75%				5.75%
5.750% Senior Notes due 2028 | Redemption Period Prior to January 15, 2021
Debt Instrument [Line Items]
Redemption percentage	105.75%
5.750% Senior Notes due 2028 | Redemption Period Prior to January 15, 2023
Debt Instrument [Line Items]
Redemption percentage	100.00%
Present value of note (as percentage)	1.02875
5.750% Senior Notes due 2028 | January 15, 2023 to January 14, 2024
Debt Instrument [Line Items]
Redemption percentage	102.875%
5.750% Senior Notes due 2028 | January 15, 2024 to January 14, 2025
Debt Instrument [Line Items]
Redemption percentage	101.917%
5.750% Senior Notes due 2028 | January 15, 2025 to January 14, 2026
Debt Instrument [Line Items]
Redemption percentage	100.958%
5.750% Senior Notes due 2028 | January 15, 2026 and thereafter
Debt Instrument [Line Items]
Redemption percentage	100.00%
5.750% Senior Notes due 2028 | Treasury Rate
Debt Instrument [Line Items]
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Treasury rate redemption (as percentage)	50.00%
5.25% Senior Notes due 2029
Debt Instrument [Line Items]
Redemption percentage	40.00%
Interest rate, stated percentage	5.25%		5.25%	5.25%
5.25% Senior Notes due 2029 | Redemption Period Prior to June 15, 2022
Debt Instrument [Line Items]
Redemption percentage	105.25%
Outstanding principal after redemption, percentage (at least)	50.00%
5.25% Senior Notes due 2029 | Redemption Period Prior to June 15, 2024
Debt Instrument [Line Items]
Redemption percentage	100.00%
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Present value of note (as percentage)	1.02625
5.25% Senior Notes due 2029 | June 15, 2024 to June 14, 2025
Debt Instrument [Line Items]
Redemption percentage	102.625%
5.25% Senior Notes due 2029 | June 15, 2025 to June 14, 2026
Debt Instrument [Line Items]
Redemption percentage	101.75%
5.25% Senior Notes due 2029 | June 15, 2026 to June 14, 2027
Debt Instrument [Line Items]
Redemption percentage	100.875%
5.25% Senior Notes due 2029 | June 15, 2027 and thereafter
Debt Instrument [Line Items]
Redemption percentage	100.00%
5.25% Senior Notes due 2029 | Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)	0.50%
3.375% Senior Notes Due 2029
Debt Instrument [Line Items]
Redemption percentage	40.00%
Interest rate, stated percentage	3.375%	3.375%
3.375% Senior Notes Due 2029 | Redemption Period Prior to February 15, 2024
Debt Instrument [Line Items]
Redemption percentage	103.375%
Outstanding principal after redemption, percentage (at least)	50.00%
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Present value of note (as percentage)	1.01688
3.375% Senior Notes Due 2029 | February 15, 2024 to February 14, 2025
Debt Instrument [Line Items]
Redemption percentage	101.688%
3.375% Senior Notes Due 2029 | February 15, 2025 to February 14, 2026
Debt Instrument [Line Items]
Redemption percentage	100.844%
3.375% Senior Notes Due 2029 | February 15, 2026 and thereafter
Debt Instrument [Line Items]
Redemption percentage	100.00%
3.375% Senior Notes Due 2029 | Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)	0.50%
3.625% Senior Notes due 2031
Debt Instrument [Line Items]
Redemption percentage	40.00%
Interest rate, stated percentage		3.625%
3.625% Senior Notes due 2031 | Redemption Period Prior to February 15, 2026
Debt Instrument [Line Items]
Redemption percentage	103.625%
Outstanding principal after redemption, percentage (at least)	50.00%
Premium percentage of principal amount of note discount factor (as percent)	1.00%
3.625% Senior Notes due 2031 | February 15, 2026 to February 14, 2027
Debt Instrument [Line Items]
Redemption percentage	101.813%
Present value of note (as percentage)	1.01813
3.625% Senior Notes due 2031 | February 15, 2027 to February 14, 2028
Debt Instrument [Line Items]
Redemption percentage	101.208%
3.625% Senior Notes due 2031 | February 15, 2028 to February 14, 2029
Debt Instrument [Line Items]
Redemption percentage	100.604%
3.625% Senior Notes due 2031 | February 15, 2029 and thereafter
Debt Instrument [Line Items]
Redemption percentage	100.00%
3.625% Senior Notes due 2031 | Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)	0.50%

Long-term Debt and Finance L_10

Long-term Debt and Finance Leases - Senior Credit Facility and Tax Exempt Bonds (Details)	Aug. 20, 2020USD ($)	May 28, 2019USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Jan. 05, 2021USD ($)	Dec. 17, 2020USD ($)	Aug. 20, 2020CAD ($)	Jun. 30, 2020USD ($)	Mar. 11, 2020USD ($)
Debt Instrument [Line Items]
Decrease to long-term debt outstanding		$ 594,000,000
Loss on debt extinguishment			$ 9,000,000	$ 51,000,000	$ 44,000,000
Long-term debt			8,855,000,000	6,042,000,000
Credit Agreement | Revolving Credit Facility | Adjusted Base Rate | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		1.25%
Credit Agreement | Revolving Credit Facility | Adjusted Base Rate | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		0.75%
Credit Agreement | Revolving Credit Facility | Eurodollar | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		2.25%
Credit Agreement | Revolving Credit Facility | Eurodollar | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		1.75%
Credit Agreement | Debt Basket
Debt Instrument [Line Items]
Revolving credit facility	$ 600,000,000
Recourse Debt
Debt Instrument [Line Items]
Long-term debt			8,855,000,000	6,008,000,000
Recourse Debt | Term Loan Facility
Debt Instrument [Line Items]
Repayment of debt		$ 1,700,000,000
Loss on debt extinguishment		17,000,000
Write off of deferred debt issuance cost		13,000,000
Recourse Debt | Term Loan Facility | Interest Rate Swap
Debt Instrument [Line Items]
Reduction to interest expense		(25,000,000)
Recourse Debt | NRG Indian River Power 2020, tax exempt bonds, due 2040
Debt Instrument [Line Items]
Long-term debt			$ 57,000,000	0			$ 57,000,000
Interest rate, stated percentage			1.25%				1.25%
Recourse Debt | NRG Indian River Power 2020, tax exempt bonds, due 2045
Debt Instrument [Line Items]
Long-term debt			$ 190,000,000	0			$ 190,000,000
Interest rate, stated percentage			1.25%				1.25%
Recourse Debt | Indian River Power, tax exempt bonds, due 2040
Debt Instrument [Line Items]
Long-term debt			$ 0	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			$ 0	190,000,000
Interest rate, stated percentage			5.375%
Recourse Debt | NRG Dunkirk 2020, tax exempt bonds, due 2042
Debt Instrument [Line Items]
Long-term debt			$ 59,000,000	0
Interest rate, stated percentage			1.30%
Recourse Debt | Dunkirk Power LLC, tax exempt bonds, due 2042
Debt Instrument [Line Items]
Long-term debt			$ 0	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	33,000,000
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	466,000,000
Aggregate principal amount										$ 59,000,000
Recourse Debt | Tax-exempt bonds | Minimum
Debt Instrument [Line Items]
Interest rate, stated percentage			1.25%							1.30%
Recourse Debt | Tax-exempt bonds | Maximum
Debt Instrument [Line Items]
Interest rate, stated percentage			4.75%
Line of Credit | Swingline facility
Debt Instrument [Line Items]
Revolving credit facility	100,000,000							$ 10,000,000	$ 50,000,000
Line of Credit | Debt Basket
Debt Instrument [Line Items]
Revolving credit facility	10,000,000,000								6,000,000,000
Line of Credit | Credit Agreement | Revolving Credit Facility
Debt Instrument [Line Items]
Increase in revolving commitments		184,000,000
Revolving credit facility	273,000,000	$ 2,600,000,000
Increase in revolving commitments and letters of credit	802,000,000
Credit facility, lien basket (greater of)	$ 10,000,000,000								6,000,000,000
Credit facility, lien basket, percentage of total assets	30.00%							30.00%
Long-term debt			$ 0	83,000,000
Line of Credit | Credit Agreement | Revolving Credit Facility | Subsequent Event
Debt Instrument [Line Items]
Revolving commitments available						$ 3,700,000,000
Line of Credit | Credit Agreement | Revolving Credit Facility | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)			1.75%
Secured Debt | Credit Agreement | Debt Basket
Debt Instrument [Line Items]
Revolving credit facility	$ 1,700,000,000								$ 750,000,000
Non Recourse Debt
Debt Instrument [Line Items]
Long-term debt			$ 0	$ 34,000,000

Long-term Debt and Finance L_11

Long-term Debt and Finance Leases - Non-Recourse Debt (Details) - USD ($)	Oct. 21, 2019	Jan. 04, 2019	Dec. 31, 2020	Dec. 02, 2020
Debt Instrument [Line Items]
Put option agreement, semi-annual Interest rate			1.65%
Put option agreement, covenant, mandatory exercise of Issuance Right, consolidated stockholder's equity (below)			$ 2,000,000,000
Delaware Trust [Member]
Debt Instrument [Line Items]
Put option agreement, term			3 years
Pre-capitalized Trust Securities
Debt Instrument [Line Items]
Sale pre-capitalized trust securities			$ 900,000,000
1.841% Senior Secured First Lien Notes due 2023
Debt Instrument [Line Items]
Interest rate, stated percentage			1.841%
Aggregate principal amount			$ 900,000,000
LC Agreement
Debt Instrument [Line Items]
Credit facility				$ 874,000,000
Agua Caliente Borrower 1, due 2038
Debt Instrument [Line Items]
Redemption percentage of principal	102.00%
Repayment of debt	$ 83,000,000
Non Recourse Debt | Letter of Credit | Credit Agreement 2019
Debt Instrument [Line Items]
Credit facility		$ 80,000,000	150,000,000
Annual facility fees, percentage		1.33%
Letter of credit			229,000,000
Non Recourse Debt | Letter of Credit | Bilateral letter of credit facilities
Debt Instrument [Line Items]
Credit facility			475,000,000
Letter of credit			$ 5,000,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of December 31, 2019	$ 728
Revisions in estimates for current obligations	26
Additions	3
Spending for current obligations	(43)
Accretion	46
Balance as of December 31, 2020	760
Nuclear Decommission
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of December 31, 2019	298
Revisions in estimates for current obligations	(12)
Additions	0
Spending for current obligations	0
Accretion	17
Balance as of December 31, 2020	303
Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of December 31, 2019	430
Revisions in estimates for current obligations	38
Additions	3
Spending for current obligations	(43)
Accretion	29
Balance as of December 31, 2020	$ 457

Benefit Plans and Other Postr_3

Benefit Plans and Other Postretirement Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)benefitPlan	Dec. 31, 2019USD ($)
Benefit Plans and Other Postretirement Benefits
Number of qualified pension plans | benefitPlan	2
Pension Benefits
Benefit Plans and Other Postretirement Benefits
Expects to contribute to the pension plans	$ 30
Actuarial loss	126	$ 207
GenOn | Restructuring Support Agreement
Benefit Plans and Other Postretirement Benefits
Expects to contribute to the pension plans	$ 14

Benefit Plans and Other Postr_4

Benefit Plans and Other Postretirement Benefits - Net Benefit Costs and Funded Status (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Annual periodic pension cost
Curtailment gain	$ (8)
Pension Benefits
Annual periodic pension cost
Service cost benefits earned		$ 10	$ 10	$ 23
Interest cost on benefit obligation		38	46	44
Expected return on plan assets		(61)	(59)	(62)
Amortization of unrecognized net loss		(5)	(3)	0
Curtailment gain		0	0	(7)
Net periodic benefit (credit)/cost		(8)	0	12
Pension and other post retirement benefit obligations
Benefit obligation at January 1		1,397	1,222
Service cost		10	10	23
Interest cost		38	46	44
Plan amendments		0	0
Actuarial loss		126	207
Employee and retiree contributions		0	0
Benefit payments		(82)	(88)
Benefit obligation at December 31		1,489	1,397	1,222
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1		1,150	981
Actual return on plan assets		193	216
Employee and retiree contributions		0	0
Employer contributions		11	41
Benefit payments		(82)	(88)
Fair value of plan assets at December 31		1,272	1,150	981
Funded status at December 31 — excess of obligation over assets		(217)	(247)
Other Postretirement Benefits Plan
Annual periodic pension cost
Service cost benefits earned		0	1	1
Interest cost on benefit obligation		3	3	4
Amortization of unrecognized prior service cost		(14)	(13)	(10)
Amortization of unrecognized net loss		(1)	0	0
Curtailment gain		0	0	(10)
Net periodic benefit (credit)/cost		(10)	(9)	(15)
Pension and other post retirement benefit obligations
Benefit obligation at January 1		93	83
Service cost		0	1	1
Interest cost		3	3	4
Plan amendments		0	(2)
Actuarial loss		0	16
Employee and retiree contributions		3	4
Benefit payments		(9)	(12)
Benefit obligation at December 31		90	93	83
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	4
Employer contributions		6	7
Benefit payments		(9)	(11)
Fair value of plan assets at December 31		0	0	$ 0
Funded status at December 31 — excess of obligation over assets		$ (90)	$ (93)

Benefit Plans and Other Postr_5

Benefit Plans and Other Postretirement Benefits - Amounts Recognized in the Balance Sheets and OCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Benefits
Amounts recognized in balance sheet
Other current liabilities	$ 0	$ 0
Other non-current liabilities	217	247
Amounts recognized in accumulated OCI
Net loss	127	138
Prior service cost/(credit)	2	2
Total/Net accumulated OCI	129	140
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial (gain)/loss	(6)	50
Amortization of net actuarial (gain)	(5)	(3)	$ 0
Prior service credit	0	0
Amortization of prior service cost	0	0
Total recognized in OCI	(11)	47
Net periodic benefit credit	(8)	0	12
Net recognized in net periodic pension credit and OCI	(19)	47
Significant components of NRG's domestic pension plan
Projected benefit obligation	1,489	1,397	1,222
Accumulated benefit obligation	1,455	1,362
Fair value of plan assets	1,272	1,150	981
Other Postretirement Benefits Plan
Amounts recognized in balance sheet
Other current liabilities	5	7
Other non-current liabilities	85	86
Amounts recognized in accumulated OCI
Net loss	6	7
Prior service cost/(credit)	(29)	(43)
Total/Net accumulated OCI	(23)	(36)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial (gain)/loss	0	16
Amortization of net actuarial (gain)	(1)	0	0
Prior service credit	0	(2)
Amortization of prior service cost	14	12
Total recognized in OCI	13	26
Net periodic benefit credit	(10)	(9)	(15)
Net recognized in net periodic pension credit and OCI	3	17
Significant components of NRG's domestic pension plan
Projected benefit obligation	90	93	83
Fair value of plan assets	$ 0	$ 0	$ 0

Benefit Plans and Other Postr_6

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, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 1,272	$ 1,150	$ 981
Weighted-Average Assumptions
Discount rate	2.56%	3.26%
Interest crediting rate	3.12%	1.62%
Rate of compensation increase	3.00%	3.00%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	3.26%
Interest crediting rate	3.66%
Expected return on plan assets	5.93%	6.35%	6.17%
Rate of compensation increase	3.00%	3.00%	3.00%
Pension Benefits | Minimum
Significant assumptions used to calculate NRG's benefit expense
Discount rate		4.38%	3.71%
Pension Benefits | Maximum
Significant assumptions used to calculate NRG's benefit expense
Discount rate		4.20%	4.04%
Pension Benefits | Common/collective trust investment — U.S. equity
Target allocations
Target allocation of pension plan assets (as percent)	20.00%
Pension Benefits | Common/collective trust investment — non-U.S. equity
Target allocations
Target allocation of pension plan assets (as percent)	13.00%
Pension Benefits | Common/collective trust investment — non-core assets
Target allocations
Target allocation of pension plan assets (as percent)	17.00%
Pension Benefits | Common/collective trust investment — fixed income
Target allocations
Target allocation of pension plan assets (as percent)	50.00%
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1)
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	$ 13	$ 12
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Common/collective trust investment — U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Common/collective trust investment — non-U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Common/collective trust investment — non-core assets
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Common/collective trust investment — fixed income
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Pension Benefits | Quoted Prices in Active Markets for Identical Assets (Level 1) | Short-term investment fund
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	13	12
Pension Benefits | Significant Observable Inputs (Level 2)
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	806	721
Pension Benefits | Significant Observable Inputs (Level 2) | Common/collective trust investment — U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	284	233
Pension Benefits | Significant Observable Inputs (Level 2) | Common/collective trust investment — non-U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	113	73
Pension Benefits | Significant Observable Inputs (Level 2) | Common/collective trust investment — non-core assets
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	151	143
Pension Benefits | Significant Observable Inputs (Level 2) | Common/collective trust investment — fixed income
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	258	272
Pension Benefits | Significant Observable Inputs (Level 2) | Short-term investment fund
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	0	0
Pension Benefits | Total
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	819	733
Pension Benefits | Total | Common/collective trust investment — U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	284	233
Pension Benefits | Total | Common/collective trust investment — non-U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	113	73
Pension Benefits | Total | Common/collective trust investment — non-core assets
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	151	143
Pension Benefits | Total | Common/collective trust investment — fixed income
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	258	272
Pension Benefits | Total | Short-term investment fund
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	13	12
Pension Benefits | Fair Value Measured at Net Asset Value Per Share
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	1,272	1,150
Pension Benefits | Fair Value Measured at Net Asset Value Per Share | Common/collective trust investment — non-U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	45	84
Pension Benefits | Fair Value Measured at Net Asset Value Per Share | Common/collective trust investment — non-core assets
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	84	24
Pension Benefits | Fair Value Measured at Net Asset Value Per Share | Common/collective trust investment — fixed income
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	289	279
Pension Benefits | Fair Value Measured at Net Asset Value Per Share | Partnerships/joint ventures
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	35	30
Other Postretirement Benefits Plan
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	$ 0	$ 0	$ 0
Weighted-Average Assumptions
Discount rate	2.54%	3.26%
Rate of compensation increase	0.00%	0.00%
Significant assumptions used to calculate NRG's benefit expense
Expected return on plan assets	0.00%	0.00%	0.00%
Rate of compensation increase	0.00%	0.00%	0.00%
Other Postretirement Benefits Plan | Minimum
Significant assumptions used to calculate NRG's benefit expense
Discount rate	3.26%	4.37%	3.71%
Interest crediting rate	2.28%
Other Postretirement Benefits Plan | Maximum
Significant assumptions used to calculate NRG's benefit expense
Discount rate			4.08%
Other Postretirement Benefits Plan | Postretirement Benefit Obligation
Weighted-Average Assumptions
Year Health care cost trend rate reaches ultimate trend rate	2028	2028
Other Postretirement Benefits Plan | Postretirement Benefit Obligation | Before age 65
Weighted-Average Assumptions
Health care trend rate	7.20%	7.50%	8.20%
Other Postretirement Benefits Plan | Postretirement Benefit Obligation | Age 65 and after
Weighted-Average Assumptions
Health care trend rate	4.50%	4.50%
Other Postretirement Benefits Plan | Net Period Benefit Cost/Credit
Weighted-Average Assumptions
Year Health care cost trend rate reaches ultimate trend rate	2028	2025	2025
Other Postretirement Benefits Plan | Net Period Benefit Cost/Credit | Before age 65
Weighted-Average Assumptions
Health care trend rate	7.50%	7.80%
Other Postretirement Benefits Plan | Net Period Benefit Cost/Credit | Age 65 and after
Weighted-Average Assumptions
Health care trend rate	4.50%	4.50%	4.50%

Benefit Plans and Other Postr_7

Benefit Plans and Other Postretirement Benefits - Expected Future Benefit Payments For the Next Five Years and Other (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
STP Defined Benefit Plans
Curtailment gain	$ 8
Increase to pension liability	$ 32
Company's contributions to 401(k) plans
Company contributions to defined contribution plans		$ 22	$ 22	$ 28
South Texas Project
STP Defined Benefit Plans
Amount reimbursed to STPNOC towards defined benefit plans		8	24
Expected reimbursement of contribution to retirement plan obligations to STPNOC in 2014		18
Pension Benefit Payments
NRG's expected future benefit payments
2021		90
2022		89
2023		87
2024		85
2025		83
2026-2030		386
STP Defined Benefit Plans
Curtailment gain		0	0	7
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans		(217)	(247)
Net periodic benefit credit		(8)	0	12
Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss)		(11)	47
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		(99)	(77)
Net periodic benefit credit		7	9
Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss)		22	(13)
Other Postretirement Benefits Plan
NRG's expected future benefit payments
2021		6
2022		6
2023		5
2024		5
2025		5
2026-2030		19
Medicare prescription drug reimbursements
2021		0
2022		0
2023		0
2024		0
2025		0
2026-2030		2
STP Defined Benefit Plans
Curtailment gain		0	0	10
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans		(90)	(93)
Net periodic benefit credit		(10)	(9)	$ (15)
Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss)		13	26
Other Postretirement Benefits Plan | South Texas Project
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans		(20)	(20)
Net periodic benefit credit		(4)	(4)
Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss)		$ 5	$ 6
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%

Capital Structure - Changes in

Capital Structure - Changes in Common Shares issued and Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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)	421,890,790
Beginning balance, treasury shares (in shares)	(172,894,601)
Beginning balance, common shares outstanding (in shares)	248,996,189
Share repurchases (in shares)	(6,062,783)	(36,301,882)	(35,234,664)
Ending balance, common shares issued (in shares)	423,057,848	421,890,790
Ending balance, treasury shares (in shares)	(178,825,915)	(172,894,601)
Ending balance, common shares outstanding (in shares)	244,231,933	248,996,189
Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued (in shares)	421,890,790	420,288,886	418,323,134
Beginning balance, common shares outstanding (in shares)	248,996,189	283,650,039	316,743,089
Shares issued under ESPP (in shares)	131,469	46,128	175,862
Shares issued from LTIP (in shares)	1,167,058	1,601,904	1,965,752
Ending balance, common shares issued (in shares)	423,057,848	421,890,790	420,288,886
Ending balance, common shares outstanding (in shares)	244,231,933	248,996,189	283,650,039
Treasury Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, treasury shares (in shares)	(172,894,601)	(136,638,847)	(101,580,045)
Shares issued under ESPP (in shares)	131,469	46,128	175,862
Shares issued from LTIP (in shares)	0	0	0
Share repurchases (in shares)	(6,062,783)	(36,301,882)	(35,234,664)
Ending balance, treasury shares (in shares)	(178,825,915)	(172,894,601)	(136,638,847)

Capital Structure - Common Stoc

Capital Structure - Common Stock (Details) - USD ($)	Jan. 21, 2021	Mar. 31, 2019	Feb. 27, 2020	Mar. 31, 2020	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Equity, Class of Treasury Stock [Line Items]
Quarterly dividends per share (usd per share)							$ 0.30	$ 0.03	$ 0.03
Dividends paid per share (in usd per share)							$ 1.20	0.12	$ 0.12
Common stock, dividends, proposed annual amount, per share (usd per share)				$ 1.20				$ 0.12
Long-term capital allocation policy, target allocation of cash generated allocated to growth investments, percentage					50.00%
Long-term capital allocation, target allocation, cash generated allocated returned to shareholders, percentage					50.00%
Eligible compensation withholding, minimum, percentage		1.00%
Eligible compensation withholding, maximum, percentage		10.00%					10.00%
Market value on offering date percentage						95.00%
Exercise price as a percentage of fair value (as a percent)		95.00%					85.00%
Treasury stock reserved for issuance under the ESPP (in shares)							2,753,591
Shares repurchased (in shares)							6,062,783	36,301,882	35,234,664
Capital Allocation Plan
Equity, Class of Treasury Stock [Line Items]
Stock repurchase program, authorized amount					$ 1,250,000,000			$ 1,250,000,000	$ 1,500,000,000
Shares repurchased (in shares)							6,774,031	37,238,810	35,234,664
2018 Capital Allocation Plan
Equity, Class of Treasury Stock [Line Items]
Shares repurchased (in shares)						250,000,000			1,250,000,000
2019 Capital Allocation Plan
Equity, Class of Treasury Stock [Line Items]
Shares repurchased (in shares)			56,000,000					1,194,000,000
Subsequent Event
Equity, Class of Treasury Stock [Line Items]
Dividends per common share (in usd per share)	$ 0.325
Scenario, Plan | Subsequent Event
Equity, Class of Treasury Stock [Line Items]
Common stock, dividends, proposed annual amount, per share (usd per share)	$ 1.30
Common stock, annual dividends increase, percentage	8.00%
Minimum
Equity, Class of Treasury Stock [Line Items]
Annual dividend growth rate, percentage					700.00%
Maximum
Equity, Class of Treasury Stock [Line Items]
Annual dividend growth rate, percentage					9.00%
Long-term incentive plans
Equity, Class of Treasury Stock [Line Items]
Long-term incentive plans (in shares)							14,862,069

Capital Structure - Summary of

Capital Structure - Summary of Changes in Shares Repurchased (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	6,062,783	36,301,882	35,234,664
Shares repurchased under May 24, 2018 Accelerated Repurchase Agreement
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)			10,829,903
Amounts paid for shares and share equivalents purchased (in millions)			$ 354
Shares repurchased under September 5, 2018 Accelerated Repurchase Agreement
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)			13,307,130
Amounts paid for shares and share equivalents purchased (in millions)			$ 500
Other repurchases
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	6,062,783	26,863,211	11,097,631
Amounts paid for shares and share equivalents purchased (in millions)	$ 197	$ 1,008	$ 396
Repurchases under February 28, 2019 Accelerated Share Repurchase Agreement
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)		9,438,671
Amounts paid for shares and share equivalents purchased (in millions)		$ 400
Equivalent shares purchased in lieu of tax withholding on equity compensation issuances
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	711,248	936,928
Average price paid per share (in shares)	$ 38.23	$ 38.78
Amounts paid for shares and share equivalents purchased (in millions)	$ 27	$ 36
Capital Allocation Plan
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	6,774,031	37,238,810	35,234,664
Average price paid per share (in shares)	$ 33.05	$ 38.79	$ 35.48
Amounts paid for shares and share equivalents purchased (in millions)	$ 224	$ 1,444	$ 1,250

Investments Accounted for by _3

Investments Accounted for by the Equity Method and Variable Interest Entities - Summary of Equity Method Investments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Nov. 30, 2020	Dec. 31, 2019
Investments Accounted for by the Equity Method
Equity investments in affiliates	$ 346		$ 388
Difference between carrying value and underlying net assets	343
Undistributed earnings by equity investment	$ 30		$ 42
Agua Caliente
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	35.00%	35.00%
Equity investments in affiliates	$ 185
Gladstone
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	37.50%
Equity investments in affiliates	$ 131
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	$ 17
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	$ 14
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
Petra Nova Parish Holdings
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	50.00%
Equity investments in affiliates	$ (13)

Investments Accounted for by _4

Investments Accounted for by the Equity Method and Variable Interest Entities - PG&E Bankruptcy (Details) - USD ($) $ in Millions	1 Months Ended
	Nov. 30, 2020	Dec. 31, 2020
Investments Accounted for by the Equity Method
Distribution received	$ 50
Agua Caliente
Investments Accounted for by the Equity Method
Ownership percentage	35.00%	35.00%
Ivanpah Master Holdings, LLC
Investments Accounted for by the Equity Method
Ownership percentage		54.50%

Investments Accounted for by _5

Investments Accounted for by the Equity Method and Variable Interest Entities - Variable Interest Entities (Details) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2018USD ($)	Dec. 31, 2020projectMW	Dec. 31, 2019USD ($)
Schedule of Equity Method Investments [Line Items]
Generation capacity (in MW) | MW		23,000
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
Gladstone
Schedule of Equity Method Investments [Line Items]
Ownership percentage		37.50%
Generation capacity (in MW) | MW		1,613

Investments Accounted for by _6

Investments Accounted for by the Equity Method and Variable Interest Entities - Other Equity Investments (Details) $ in Millions	3 Months Ended
	Dec. 31, 2020USD ($)MW	Dec. 31, 2019USD ($)
Schedule of Equity Method Investments [Line Items]
Generation capacity (in MW) | MW	23,000
Equity investments in affiliates	$ 346	$ 388
Gladstone
Schedule of Equity Method Investments [Line Items]
Ownership percentage	37.50%
Generation capacity (in MW) | MW	1,613
Equity investments in affiliates	$ 131
Home Solar
Schedule of Equity Method Investments [Line Items]
Cash received	$ 66

Investments Accounted for Using

Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs - Summarized Financial Information (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Accounts receivable, net	$ 904	$ 1,025
Other non-current assets	216	240
Total Assets	14,902	12,531
Current liabilities	1,915	2,359
Long-term debt	8,855	6,042
Other non-current liabilities	1,066	1,084
Total Liabilities	13,222	10,853
Variable Interest Entity, Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Accounts receivable, net	647	3
Other current assets	2	0
Net property, plant and equipment	0	71
Other non-current assets	0	27
Total Assets	649	101
Current liabilities	78	4
Long-term debt	0	24
Other non-current liabilities	0	8
Total Liabilities	78	36
Redeemable noncontrolling interests	0	20
Net assets less noncontrolling interests	$ 571	$ 45

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Basic income per share attributable to NRG, Inc;
Net Income/(Loss) Attributable to NRG Energy, Inc.	$ 510	$ 4,438	$ 268
Weighted average number of common shares outstanding — basic (in shares)	245,000,000	262,000,000	304,000,000
Income/(Loss) per weighted average common share — basic (in usd per share)	$ 2.08	$ 16.94	$ 0.88
Incremental shares attributable to the issuance of equity compensation (treasury stock method) (in shares)	1,000,000	2,000,000	4,000,000
Weighted average number of common shares outstanding — diluted (in shares)	246,000,000	264,000,000	308,000,000
Income per weighted average common share — diluted (in usd per share)	$ 2.07	$ 16.81	$ 0.87

Segment Reporting (Details)

Segment Reporting (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement
Revenues	$ 9,093	$ 9,821	$ 9,478
Operating expenses	7,473	8,153	7,997
Depreciation and amortization	435	373	421
Impairment losses	75	5	99
Development costs	8	7	11
Total operating cost and expenses	7,991	8,538	8,528
(Loss)/gain on sale of assets	3	7	32
Operating income/(loss)	1,105	1,290	982
Equity in (losses)/earnings of unconsolidated affiliates	17	2	9
Impairment losses on investments	(18)	(108)	(15)
Other income, net	67	66	18
Loss on debt extinguishment	(9)	(51)	(44)
Interest expense	(401)	(413)	(483)
Income from Continuing Operations Before Income Taxes	761	786	467
Income tax expense/(benefit)	251	(3,334)	7
Income from Continuing Operations	510	4,120	460
Income/(loss) from discontinued operations, net of income tax	0	321	(192)
Net Income	510	4,441	268
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests	0	3	0
Net Income Attributable to NRG Energy, Inc.	510	4,438	268
Balance sheet
Equity investments in affiliates	346	388
Capital expenditures	230	228
Goodwill	579	579
Total assets	14,902	12,531
Corporate
Income Statement
Revenues	0
Operating expenses	57
Depreciation and amortization	34
Impairment losses	0
Development costs	0
Total operating cost and expenses	91
(Loss)/gain on sale of assets	5
Operating income/(loss)	(86)
Equity in (losses)/earnings of unconsolidated affiliates	0
Impairment losses on investments	0
Other income, net	41
Loss on debt extinguishment	0
Interest expense	(384)
Income from Continuing Operations Before Income Taxes	(429)
Income tax expense/(benefit)	250
Net Income Attributable to NRG Energy, Inc.	(679)
Balance sheet
Equity investments in affiliates	0
Capital expenditures	25
Goodwill	0
Total assets	11,152
Eliminations
Income Statement
Revenues	(4)	(7)	(18)
Operating expenses	(4)	(7)	(18)
Depreciation and amortization	0	0	0
Impairment losses	0	0	0
Development costs	0	0	0
Total operating cost and expenses	(4)	(7)	(18)
(Loss)/gain on sale of assets	0	0	0
Operating income/(loss)	0	0	0
Equity in (losses)/earnings of unconsolidated affiliates	0	0	0
Impairment losses on investments	0	0	0
Other income, net	0	0	0
Loss on debt extinguishment	0	0	0
Interest expense	0	0	0
Income from Continuing Operations Before Income Taxes	0	0	0
Income tax expense/(benefit)	0	0	0
Income from Continuing Operations		0	0
Income/(loss) from discontinued operations, net of income tax		0	0
Net Income		0	0
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests		0	0
Net Income Attributable to NRG Energy, Inc.	0	0	0
Balance sheet
Equity investments in affiliates	0	0
Capital expenditures	0	0
Goodwill	0	0
Total assets	(7,360)	(4,872)
Texas | Operating Segments
Income Statement
Revenues	6,309	7,069	6,401
Operating expenses	5,246	5,818	5,399
Depreciation and amortization	227	188	156
Impairment losses	14	1	5
Development costs	4	3	3
Total operating cost and expenses	5,491	6,010	5,563
(Loss)/gain on sale of assets	0	0	4
Operating income/(loss)	818	1,059	842
Equity in (losses)/earnings of unconsolidated affiliates	(12)	(4)	(3)
Impairment losses on investments	(18)	(103)	(15)
Other income, net	11	20	13
Loss on debt extinguishment	0	0	0
Interest expense	0	0	0
Income from Continuing Operations Before Income Taxes	799	972	837
Income tax expense/(benefit)	0	0	0
Income from Continuing Operations		972	837
Income/(loss) from discontinued operations, net of income tax		0	0
Net Income		972	837
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests		0	0
Net Income Attributable to NRG Energy, Inc.	799	972	837
Balance sheet
Equity investments in affiliates	(13)	6
Capital expenditures	130	136
Goodwill	325	325
Total assets	7,641	5,711
Texas | Eliminations
Income Statement
Revenues	(6)	(1)	(19)
East | Operating Segments
Income Statement
Revenues	2,354	2,319	2,371
Operating expenses	1,828	1,895	2,024
Depreciation and amortization	142	121	105
Impairment losses	0	0	82
Development costs	3	3	3
Total operating cost and expenses	1,973	2,019	2,214
(Loss)/gain on sale of assets	0	1	0
Operating income/(loss)	381	301	157
Equity in (losses)/earnings of unconsolidated affiliates	0	0	0
Impairment losses on investments	0	0	0
Other income, net	7	6	2
Loss on debt extinguishment	(4)	0	0
Interest expense	(14)	(18)	(22)
Income from Continuing Operations Before Income Taxes	370	289	137
Income tax expense/(benefit)	(1)	2	1
Income from Continuing Operations		287	136
Income/(loss) from discontinued operations, net of income tax		0	0
Net Income		287	136
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests		0	0
Net Income Attributable to NRG Energy, Inc.	371	287	136
Balance sheet
Equity investments in affiliates	0	0
Capital expenditures	45	30
Goodwill	254	254
Total assets	1,885	2,160
East | Eliminations
Income Statement
Revenues	6	(8)	5
West/Other | Operating Segments
Income Statement
Revenues	434	440	724
Operating expenses	346	397	467
Depreciation and amortization	32	33	127
Impairment losses	61	4	12
Development costs	1	1	3
Total operating cost and expenses	440	435	609
(Loss)/gain on sale of assets	(2)	0	(2)
Operating income/(loss)	(8)	5	113
Equity in (losses)/earnings of unconsolidated affiliates	29	6	13
Impairment losses on investments	0	0	0
Other income, net	8	10	4
Loss on debt extinguishment	(5)	(3)	0
Interest expense	(3)	(10)	(39)
Income from Continuing Operations Before Income Taxes	21	8	91
Income tax expense/(benefit)	2	1	0
Income from Continuing Operations		7	91
Income/(loss) from discontinued operations, net of income tax		0	0
Net Income		7	91
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests		3	5
Net Income Attributable to NRG Energy, Inc.	19	4	86
Balance sheet
Equity investments in affiliates	359	382
Capital expenditures	30	25
Goodwill	0	0
Total assets	1,584	1,190
West/Other | Eliminations
Income Statement
Revenues	$ (4)	2	(4)
Corporate | Operating Segments
Income Statement
Revenues		0	0
Operating expenses		50	125
Depreciation and amortization		31	33
Impairment losses		0	0
Development costs		0	2
Total operating cost and expenses		81	160
(Loss)/gain on sale of assets		6	30
Operating income/(loss)		(75)	(130)
Equity in (losses)/earnings of unconsolidated affiliates		0	(1)
Impairment losses on investments		(5)	0
Other income, net		30	(1)
Loss on debt extinguishment		(48)	(44)
Interest expense		(385)	(422)
Income from Continuing Operations Before Income Taxes		(483)	(598)
Income tax expense/(benefit)		(3,337)	6
Income from Continuing Operations		2,854	(604)
Income/(loss) from discontinued operations, net of income tax		321	(192)
Net Income		3,175	(796)
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests		0	(5)
Net Income Attributable to NRG Energy, Inc.		3,175	$ (791)
Balance sheet
Equity investments in affiliates		0
Capital expenditures		37
Goodwill		0
Total assets		$ 8,342
Customer Concentration Risk | Texas
Segment Reporting Information
Concentration risk, percentage	10.00%		11.00%

Income Taxes - Income Tax Provi

Income Taxes - Income Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current
State	$ 22	$ 2	$ 6
Foreign	4	4	0
Total — current	26	6	6
Deferred
U.S. Federal	168	(3,000)	(16)
State	60	(340)	16
Foreign	(3)	0	1
Total — deferred	225	(3,340)	1
Total income tax expense/(benefit)	251	(3,334)	7
Domestic and foreign components of income from continuing operations before income tax expense
U.S.	749	771	468
Foreign	12	15	(1)
Income from Continuing Operations Before Income Taxes	761	786	467
Reconciliation of the U.S. federal statutory rate to NRG's effective rate from continuing operations
Income from continuing operations before income taxes	761	786	467
Tax at federal statutory tax rate	160	165	98
State taxes	18	13	18
Permanent differences	8	(9)	7
Changes in valuation allowance	24	(3,492)	(106)
Deferred impact of state tax rate changes	2	12	0
Production tax credits ("PTC")	0	0	(7)
Recognition of uncertain tax benefits	3	(10)	1
Return to provision adjustments	36	0	0
Alternative minimum tax ("AMT") refundable credit	0	0	(4)
Other	0	(13)	0
Total income tax expense/(benefit)	$ 251	$ (3,334)	$ 7
Effective income tax rate (as a percent)	33.00%	(424.20%)	1.50%

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	$ 79	$ 81
Difference between book and tax basis of property	357	548
Pension and other postretirement benefits	86	86
Equity compensation	10	11
Bad debt reserve	16	13
Derivatives, net	11	0
U.S. Federal net operating loss carryforwards	2,117	2,116
Foreign net operating loss carryforwards	102	105
State net operating loss carryforwards	351	360
Federal and state tax credit carryforwards	384	384
Federal benefit on state uncertain tax positions	4	4
Interest disallowance carryforward per §163(j) of the Tax Act	4	82
Inventory obsolescence	6	7
Other	10	3
Total deferred tax assets	3,537	3,800
Deferred tax liabilities:
Emissions allowances	21	19
Derivatives, net	0	27
Goodwill	29	8
Intangibles amortization (excluding goodwill)	2	15
Equity method investments	156	201
Convertible Debt	16	19
Total deferred tax liabilities	224	289
Total deferred tax assets less deferred tax liabilities	3,313	3,511
Valuation allowance	(266)	(242)
Net deferred tax asset	3,047	3,269
NRG's net deferred tax position
Deferred tax asset	3,066	3,286
Deferred tax liability	(19)	(17)
Net deferred tax asset	$ 3,047	$ 3,269

Income Taxes -Narrative for Def

Income Taxes -Narrative for Deferred Tax Assets and Valuation Allowance, Taxes Receivable and Payable (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Taxes receivable and payable
Valuation allowance - current period activities	$ (24)	$ 3,492	$ 106
NOLs utilized		593
Deferred tax asset	3,047	3,269
Net deferred tax asset (before valuation)	3,300	3,500
Valuation allowance	266	$ 242
Current taxes payable	12
Current taxes receivable	1
Federal Tax Authority
Taxes receivable and payable
Operating loss carryforwards	2,100
State and Local Jurisdiction
Taxes receivable and payable
Operating loss carryforwards	351
Foreign Tax Authority
Taxes receivable and payable
Operating loss carryforwards	$ 102

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Uncertain Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Uncertain tax benefits
Uncertain tax benefits	$ 15	$ 26	$ 15	$ 15
Liability for uncertainty in income taxes, noncurrent			18	17
Unrecognized tax benefits, income tax penalties expense	1
Accrued interest and penalties related to unrecognized tax benefits			$ 3	$ 2
Uncertain tax benefits reconciliation
Balance as of January 1	15	26
Increase due to current year positions	3	2
Settlements, payments and statute closure	(3)	(13)
Uncertain tax benefits as of December 31	$ 15	$ 15

Stock-Based Compensation - Long

Stock-Based Compensation - Long-Term Incentive Plan (Details) - shares	Apr. 27, 2017	Dec. 31, 2020	Dec. 31, 2019
NRG LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase in the number of shares available for issuance (in shares)	3,000,000
Number of shares authorized for issuance under plan (in shares)		25,000,000	25,000,000
Number of shares available for grant under plan (in shares)		9,385,730	9,935,750
NRG GenOn LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance under plan (in shares)	0
Number of shares available for grant under plan (in shares)		78,903	319,264

Stock-Based Compensation - Rest

Stock-Based Compensation - Restricted Stock Units (RSUs (Details) - RSUs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Stock-Based Compensation
Award vesting period	3 years
Units
Non-vested at beginning of period (in shares)	717,239
Granted (in shares)	271,718
Forfeited (in shares)	(16,750)
Vested (in shares)	(452,693)
Non-vested at end of period (in shares)	519,514	717,239
Weighted Average Grant Date Fair Value per Unit
Non-vested at beginning of period (in usd per share)	$ 25.56
Granted (in usd per share)	38.05	$ 37.37	$ 28.90
Forfeited (in usd per share)	35.86
Vested (in usd per share)	20.73
Non-vested at end of period (in usd per share)	$ 35.87	$ 25.56
Vested in period, fair value	$ 17	$ 36	$ 42
Weighted average grant date fair value (in usd per share)	$ 38.05	$ 37.37	$ 28.90

Stock-Based Compensation - Defe

Stock-Based Compensation - Deferred Stock Units, DSUs (Details) - DSUs - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Units
Balance outstanding at the beginning of the period (in shares)	331,223
Granted (in shares)	58,861
Converted to Common Stock (in shares)	(47,378)
Balance outstanding at the end of the period (in shares)	342,706	331,223
Weighted Average Grant Date Fair Value per Unit
Balance outstanding at the beginning of the period, (in usd per share)	$ 23.98
Granted (in usd per share)	35.59	$ 34.84	$ 33.43
Vested (in usd per share)	26.87
Balance outstanding at the end of the period (in usd per share)	$ 25.37	$ 23.98
Aggregate intrinsic value for DSUs outstanding	$ 13,000,000	$ 13,000,000	$ 13,000,000
Aggregate intrinsic values for DSUs converted to common stock during the period	$ 2,000,000	$ 2,000,000	$ 6,000,000
Weighted average grant date fair value (in usd per share)	$ 35.59	$ 34.84	$ 33.43

Stock -Based Compensation - Per

Stock -Based Compensation - Performance Stock Units, RPSUs and MSUs Plan description (Details)	12 Months Ended
	Dec. 31, 2020shares
RPSUs
Stock-Based Compensation
Award vesting period	3 years
Award vesting right, percentage	200.00%
RPSUs | Share-based Payment Arrangement, Tranche One
Stock-Based Compensation
Award vesting right, percentage	0.00%
RPSUs | Share-based Payment Arrangement, Tranche Two
Stock-Based Compensation
Award vesting right, percentage	25.00%
RPSUs | Share-based Payment Arrangement, Tranche Three
Stock-Based Compensation
Award vesting right, percentage	100.00%
RPSUs | Share-based Payment Arrangement, Tranche Four
Stock-Based Compensation
Award vesting right, percentage	15.00%
RPSUs | Share-based Payment Arrangement, Tranche Five
Stock-Based Compensation
Award vesting right, percentage	200.00%
MSUs
Stock-Based Compensation
Award vesting right, percentage	200.00%
MSUs | Share-based Payment Arrangement, Tranche One
Stock-Based Compensation
Award vesting right, percentage	25.00%
Vested (in shares)	0
MSUs | Share-based Payment Arrangement, Tranche Two
Stock-Based Compensation
Award vesting right, percentage	25.00%
MSUs | Share-based Payment Arrangement, Tranche Three
Stock-Based Compensation
Award vesting right, percentage	25.00%
MSUs | Share-based Payment Arrangement, Tranche Four
Stock-Based Compensation
Award vesting right, percentage	100.00%
MSUs | Share-based Payment Arrangement, Tranche Five
Stock-Based Compensation
Award vesting right, percentage	100.00%

Stock-Based Compensation - Perf

Stock-Based Compensation - Performance Stock Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
PSUs
Units
Non-vested at beginning of period (in shares)	1,200,541
Granted (in shares)	928,215
Forfeited (in shares)	(5,142)
Vested (in shares)	(1,330,053)
Non-vested at end of period (in shares)	793,561	1,200,541
Weighted Average Grant-Date Fair Value per Unit
Non-vested at beginning of period (in usd per share)	$ 26.65
Granted (in usd per share)	23.75	$ 22.50	$ 35.36
Forfeited (in usd per share)	35.77
Vested (in usd per share)	15.91
Non-vested at end of period (in usd per share)	41.69	$ 26.65
RPSUs
Weighted Average Grant-Date Fair Value per Unit
Granted (in usd per share)	$ 45.60
Award vesting, percentage	200.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility	30.15%	40.72%	47.52%	43.96%
Expected term (in years)	3 years	3 years	3 years	3 years
Risk free rate	1.58%	2.45%	2.01%	1.50%
RPSUs | 2017
Weighted Average Grant-Date Fair Value per Unit
Granted (in usd per share)	$ 15.91
MSUs
Units
Non-vested at end of period (in shares)	4,260
Weighted Average Grant-Date Fair Value per Unit
Granted (in usd per share)	$ 15.28
Award vesting, percentage	200.00%
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 - Non-

Stock-Based Compensation - Non-Qualified Stock Options (Details) - NQSOs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Stock-Based Compensation
Shares granted during the period (in shares)	0	0	0
Maximum contractual term for outstanding options (in years)	10 years
NQSO activity and changes
Outstanding at the beginning of the period (in shares)	134,398
Forfeited (in shares)	(9,083)
Exercised (in shares)	(48,268)
Outstanding at the end of the period (in shares)	77,047	134,398
Exercisable at the end of the period (in shares)	77,047
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding (in usd per share)	$ 25.31
Forfeited (in usd per share)	37.44
Exercised (in usd per share)	23.33
Outstanding (in usd per share)	25.13	$ 25.31
Exercisable (in usd per share)	$ 25.13
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures
Weighted Average Remaining Contractual Term, Outstanding (in years)	6 months	1 year
Weighted Average Remaining Contractual Term, Exercisable (in years)	6 months
Aggregate Intrinsic Value	$ 1	$ 2
Aggregate Intrinsic Value, Exercisable	$ 1

Stock-Based Compensation - Intr

Stock-Based Compensation - Intrinsic Value of Options Exercised and Cash Received (Details) - NQSOs - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total intrinsic value of options exercised	$ 1	$ 2	$ 10
Cash received from options exercised	$ 1	$ 3	$ 24

Stock-Based Compensation - Supp

Stock-Based Compensation - Supplemental Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Stock-Based Compensation
Minimum tax withholdings	$ 27	$ 36	$ 19
Compensation Expense	27	32	41
Tax detriment recognized	(9)	(12)	(4)
Unrecognized Total Cost	23
RSUs
Stock-Based Compensation
Compensation Expense	9	9	12
Unrecognized Total Cost	$ 7
Weighted Average Recognition Period Remaining (In years)	1 year 1 month 24 days
Award vesting period	3 years
DSUs
Stock-Based Compensation
Compensation Expense	$ 2	2	2
Unrecognized Total Cost	$ 0
Weighted Average Recognition Period Remaining (In years)	0 years
MSUs
Stock-Based Compensation
Compensation Expense	$ 0	0	4
Unrecognized Total Cost	$ 0
Weighted Average Recognition Period Remaining (In years)	3 days
RPSUs
Stock-Based Compensation
Compensation Expense	$ 10	10	7
Unrecognized Total Cost	$ 10
Weighted Average Recognition Period Remaining (In years)	11 months 12 days
Award vesting period	3 years
PRSUs
Stock-Based Compensation
Compensation Expense	$ 6	$ 11	$ 16
Unrecognized Total Cost	$ 6
Weighted Average Recognition Period Remaining (In years)	1 year 2 months 26 days
Award vesting period	3 years

Related Party Transactions - Su

Related Party Transactions - Summary of Material Related Party Transactions With Third Party Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	$ 52	$ 44	$ 32
Gladstone
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	4	4	3
GenConn
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	0	0	4
Ivanpah
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	43	35	20
Midway-Sunset
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	$ 5	$ 5	$ 5

Related Party Transactions - Se

Related Party Transactions - Service Agreement and Transition Service Agreement with GeOn (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
GenOn | Transition Services Agreement | Restructuring Support Agreement
Related Party Transaction [Line Items]
Shared service, selling, general and administrative	$ 53

Commitments and Contingencies -

Commitments and Contingencies - Transportation and Purchased Power Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Coal, Gas and Transportation Commitments
Commitments and Contingencies
Purchases under coal, gas and transportation arrangement	$ 800	$ 1,200	$ 1,200
Minimum purchase commitment
2021	146
2022	98
2023	69
2024	67
2025	65
Thereafter	80
Total	525
Purchases under power contracts	800	1,200	1,200
Renewable Purchased Power Agreements
Commitments and Contingencies
Purchases under coal, gas and transportation arrangement	142	183	138
Minimum purchase commitment
2021	48
2022	62
2023	50
2024	50
2025	49
Thereafter	316
Total	575
Purchases under power contracts	$ 142	$ 183	$ 138

Commitments and Contingencies_2

Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)assessmentcase	Jun. 19, 2019facility
Loss Contingencies [Line Items]
Nuclear insurance liability limit per incident	$ 13,800
Required nuclear liability insurance	450
Nuclear financial protection pool mandated by the Price-Anderson Act	13,300
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident	$ 138
Maximum assessment, administrative fee (as percent)	5.00%
Maximum assessment payment mandated by Price-Anderson Act for a nuclear incident	$ 21
Maximum assessment	44.00%
Nuclear operator maximum annual assessment	$ 9
Maximum liability per nuclear incident	61
Mutual property insurance additional blanket policy property coverage	1,300
Nuclear property insurance coverage limit per individual insured	1,500
Lost revenue insurance maximum weekly recovery	3
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	$ 2
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
Sierra Club Et Al V. Midwest Generation L L C
Loss Contingencies [Line Items]
Number of facilities | facility		4
XOOM Energy Litigation
Loss Contingencies [Line Items]
Number of class action lawsuits | case	2
High
Loss Contingencies [Line Items]
Multiplier that the industry mutual insurance company may assess against insureds premium | assessment	10
Low
Loss Contingencies [Line Items]
Multiplier that the industry mutual insurance company may assess against insureds premium | assessment	6
Nuclear Event
Loss Contingencies [Line Items]
Total nuclear property insurance coverage	$ 2,800
Lost revenue insurance maximum weekly recovery	274
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	216
Non-nuclear Event
Loss Contingencies [Line Items]
Total nuclear property insurance coverage	1,000
Lost revenue insurance maximum weekly recovery	184
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	$ 144

Regulatory Matters (Details)

Regulatory Matters (Details) $ in Thousands	Jan. 08, 2021USD ($)
Subsequent Event
Subsequent Event [Line Items]
Civil penalty	$ 85

Cash Flow Information (Details)

Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Cash Flow Information [Abstract]
Interest paid, net of amount capitalized	$ 340	$ 372	$ 436
Income taxes paid, net of refunds	24	8	9
(Decreases)/additions to fixed assets for accrued capital expenditures	$ (6)	$ 1	$ 20

Guarantees - Schedule of Maximu

Guarantees - Schedule of Maximum Potential Exposure (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Guarantor Obligations
Under 1 Year	$ 1,135
1-3 Years	355
3-5 Years	57
Over 5 Years	199
Guarantees by Remaining Maturity, Total	1,746	$ 2,010
Letters of credit and surety bonds
Guarantor Obligations
Under 1 Year	1,049
1-3 Years	73
3-5 Years	31
Over 5 Years	0
Guarantees by Remaining Maturity, Total	1,153	1,024
Asset sales guarantee obligations
Guarantor Obligations
Under 1 Year	86
1-3 Years	282
3-5 Years	26
Over 5 Years	112
Guarantees by Remaining Maturity, Total	506	698
Other guarantees
Guarantor Obligations
Under 1 Year	0
1-3 Years	0
3-5 Years	0
Over 5 Years	87
Guarantees by Remaining Maturity, Total	$ 87	$ 288

Guarantees - Narrative (Details

Guarantees - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Guarantor Obligations
Guarantee obligation	$ 1,746	$ 2,010
Letters of credit and surety bonds
Guarantor Obligations
Guarantee obligation	$ 1,153	1,024
Letters of credit and surety bonds, maximum expiration period (in years)	1 year
Asset sales guarantee obligations
Guarantor Obligations
Guarantee obligation	$ 506	$ 698
California property tax indemnity	$ 176

Jointly Owned Plants (Details)

Jointly Owned Plants (Details) $ in Millions	Dec. 31, 2020USD ($)
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	$ 428
Accumulated Depreciation	(227)
Construction in Progress	$ 1
Cedar Bayou Unit 4, Baytown, TX
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	50.00%
Property, Plant & Equipment	$ 220
Accumulated Depreciation	(101)
Construction in Progress	$ 9

SCHEDULE II - VALUATION AND Q_3

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Allowance for doubtful accounts, deducted from accounts receivable
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	$ 43	$ 32	$ 28
Charged to Costs and Expenses	108	95	83
Charged to Other Accounts	0	0	0
Deductions	(84)	(84)	(79)
Balance at End of Period	67	43	32
Income tax valuation allowance, deducted from deferred tax assets
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	242	3,794	1,863
Charged to Costs and Expenses	24	(3,543)	1,934
Charged to Other Accounts	0	(9)	(128)
Deductions	0	0	125
Balance at End of Period	$ 266	$ 242	$ 3,794