0001013871-22-000010 | 10-K | XBRL Viewer

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Revenues
Total operating revenues	$ 26,989	$ 9,093	$ 9,821
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)	20,482	6,540	7,303
Depreciation and amortization	785	435	373
Impairment losses	544	75	5
Selling, general and administrative costs	1,293	810	760
Provision for credit losses	698	108	95
Acquisition-related transaction and integration costs	93	23	2
Total operating costs and expenses	23,895	7,991	8,538
Gain on sale of assets	247	3	7
Operating Income	3,341	1,105	1,290
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	17	17	2
Impairment losses on investments	0	(18)	(108)
Other income, net	63	67	66
Loss on debt extinguishment	(77)	(9)	(51)
Interest expense	(485)	(401)	(413)
Total other expense	(482)	(344)	(504)
Income from Continuing Operations Before Income Taxes	2,859	761	786
Income tax expense/(benefit)	672	251	(3,334)
Income from Continuing Operations	2,187	510	4,120
Income from discontinued operations, net of income tax	0	0	321
Net Income	2,187	510	4,441
Less: Net income attributable to redeemable noncontrolling interest	0	0	3
Net Income Attributable to NRG Energy, Inc.	$ 2,187	$ 510	$ 4,438
Income Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic (in shares)	245,000,000	245,000,000	262,000,000
Income from continuing operations per weighted average common share —basic (in usd per share)	$ 8.93	$ 2.08	$ 15.71
Income/(loss) from discontinued operations per weighted average common share — basic (in usd per share)	0	0	1.23
Net Income per Weighted Average Common Share - Basic (in usd per share)	$ 8.93	$ 2.08	$ 16.94
Weighted average number of common shares outstanding — diluted (in shares)	245,000,000	246,000,000	264,000,000
Income from continuing operations per weighted average common share — diluted (in usd per share)	$ 8.93	$ 2.07	$ 15.59
Income/(loss) from discontinued operations per weighted average common share — diluted (in usd per share)	0	0	1.22
Net Income per Weighted Average Common Share - Diluted (in usd per share)	$ 8.93	$ 2.07	$ 16.81

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Income	$ 2,187	$ 510	$ 4,441
Other Comprehensive Income/(Loss), net of tax
Foreign currency translation adjustments, net of income tax	(5)	8	(1)
Available-for-sale securities, net of income tax	0	0	(19)
Defined benefit plans, net of income tax	85	(22)	(78)
Other comprehensive income/(loss)	80	(14)	(98)
Comprehensive Income	2,267	496	4,343
Less: Net income attributable to redeemable noncontrolling interest	0	0	3
Comprehensive Income Attributable to NRG Energy, Inc.	$ 2,267	$ 496	$ 4,340

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 250	$ 3,905
Funds deposited by counterparties	845	19
Restricted cash	15	6
Accounts receivable, net	3,245	904
Uplift securitization proceeds receivable from ERCOT	689	0
Inventory	498	327
Derivative instruments	4,613	560
Cash collateral paid in support of energy risk management activities	291	50
Prepayments and other current assets	395	257
Total current assets	10,841	6,028
Property, plant and equipment, net	1,688	2,547
Other Assets
Equity investments in affiliates	157	346
Operating lease right-of-use assets, net	271	301
Goodwill	1,795	579
Intangible assets, net	2,511	668
Nuclear decommissioning trust fund	1,008	890
Derivative instruments	2,527	261
Deferred Income Tax Assets, Net	2,155	3,066
Other non-current assets	229	216
Total other assets	10,653	6,327
Total Assets	23,182	14,902
Current Liabilities
Current portion of long-term debt and finance leases	4	1
Current portion of operating lease liabilities	81	69
Accounts payable	2,274	649
Derivative instruments	3,387	499
Cash collateral received in support of energy risk management activities	845	19
Accrued expenses and other current liabilities	1,324	678
Total current liabilities	7,915	1,915
Other Liabilities
Long-term debt and finance leases	7,966	8,691
Non-current operating lease liabilities	236	278
Nuclear decommissioning reserve	321	303
Nuclear decommissioning trust liability	666	565
Derivative instruments	1,412	385
Deferred income taxes	73	19
Other non-current liabilities	993	1,066
Total other liabilities	11,667	11,307
Total Liabilities	19,582	13,222
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,547,174 and 423,057,848 shares issued; and 243,753,899 and 244,231,933 shares outstanding at December 31, 2021 and 2020, respectively	4	4
Additional paid-in capital	8,531	8,517
Retained earnings/(accumulated deficit)	464	(1,403)
Treasury stock, at cost; 179,793,275 and 178,825,915 shares at December 31, 2021 and 2020, respectively	(5,273)	(5,232)
Accumulated other comprehensive loss	(126)	(206)
Total Stockholders' Equity	3,600	1,680
Total Liabilities and Stockholders' Equity	$ 23,182	$ 14,902

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
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)	423,547,174	423,057,848
Common stock, shares outstanding (in shares)	243,753,899	244,231,933
Treasury stock, shares (in shares)	179,793,275	178,825,915

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Operating Activities
Net Income	$ 2,187	$ 510	$ 4,441
Income from discontinued operations, net of income tax	0	0	321
Income from continuing operations	2,187	510	4,120
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions from and equity in earnings of unconsolidated affiliates	20	45	14
Depreciation and amortization	785	435	373
Accretion of asset retirement obligations	30	45	51
Provision for credit losses	698	108	95
Amortization of nuclear fuel	51	54	52
Amortization of financing costs and debt discounts	39	48	26
Loss on debt extinguishment	77	9	51
Amortization of in-the-money contracts and emission allowances	106	70	72
Amortization of unearned equity compensation	21	22	20
Net gain on sale of assets and disposal of assets	(261)	(23)	(23)
Impairment losses	544	93	113
Changes in derivative instruments	(3,626)	137	34
Changes in deferred income taxes and liability for uncertain tax benefits	604	228	(3,353)
Changes in collateral deposits in support of risk management activities	797	127	105
Changes in nuclear decommissioning trust liability	40	51	37
Oil lower of cost or market adjustment	0	29	0
Uplift securitization proceeds receivable from ERCOT	(689)	0	0
Cash (used)/provided by changes in other working capital, net of acquisition and disposition effects:
Accounts receivable - trade	(1,232)	0	5
Inventory	(61)	27	22
Prepayments and other current assets	31	4	29
Accounts payable	476	(56)	(177)
Accrued expenses and other current liabilities	(55)	(42)	(75)
Other assets and liabilities	(89)	(84)	(186)
Cash provided by continuing operations	493	1,837	1,405
Cash provided by discontinued operations	0	0	8
Net Cash Provided by Operating Activities	493	1,837	1,413
Cash Flows from Investing Activities
Payments for acquisitions of assets, businesses and leases	(3,559)	(284)	(355)
Capital expenditures	(269)	(230)	(228)
Net (purchases)/sales of emissions allowances	0	(10)	11
Investments in nuclear decommissioning trust fund securities	(751)	(492)	(416)
Proceeds from sales of nuclear decommissioning trust fund securities	710	439	381
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	830	81	1,294
Changes in investments in unconsolidated affiliates	0	2	(91)
Net contributions to discontinued operations	0	0	(44)
Other	0	0	6
Cash (used)/provided by continuing operations	(3,039)	(494)	558
Cash used by discontinued operations	0	0	(2)
Net Cash (Used)/Provided by Investing Activities	(3,039)	(494)	556
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt	1,100	3,234	1,833
Payments for short and long-term debt	(1,861)	(335)	(2,571)
Payments of dividends to common stockholders	(319)	(295)	(32)
Net receipts/(payments) from settlement of acquired derivatives that include financing elements	938	(7)	(4)
Payments for share repurchase activity	(48)	(229)	(1,440)
Payments for debt extinguishment costs	(65)	(5)	(26)
Payments of debt issuance costs	(18)	(75)	(35)
Net (repayments)/proceeds of Revolving Credit Facility	0	(83)	83
Proceeds from issuance of common stock	1	1	3
Purchase of and distributions to noncontrolling interests from subsidiaries	0	(2)	(2)
Cash (used)/provided by continuing operations	(272)	2,204	(2,191)
Cash provided by discontinued operations	0	0	43
Net Cash (Used)/Provided by Financing Activities	(272)	2,204	(2,148)
Effect of exchange rate changes on cash and cash equivalents	(2)	(2)	0
Change in Cash from discontinued operations	0	0	49
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(2,820)	3,545	(228)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	3,930	385	613
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$ 1,110	$ 3,930	$ 385

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($)
$ in Millions

Total

Common Stock

Additional Paid-In Capital

Retained Earnings/ (Accumulated Deficit)

Treasury Stock

Accumulated Other Comprehensive Loss

Beginning balance at Dec. 31, 2018

$ (1,234)

$ 4

$ 8,510

$ (6,022)

$ (3,632)

$ (94)

Increase (Decrease) in Stockholders' Equity

Net loss (income)

4,438

Other comprehensive loss

(98)

Shares reissuance for ESPP

Share repurchases

(1,409)

Equity-based awards activity, net

^[1]

(16)

Issuance of common stock

Common stock dividends

^[2]

(32)

Ending balance at Dec. 31, 2019

1,658

8,501

(1,616)

(5,039)

(192)

Increase (Decrease) in Stockholders' Equity

Net loss (income)

510

Other comprehensive loss

(14)

Repurchase of partners' equity interest in VIE

Shares reissuance for ESPP

Share repurchases

(197)

Equity-based awards activity, net

^[1]

(3)

Issuance of common stock

Common stock dividends

^[2]

(297)

Ending balance at Dec. 31, 2020

1,680

8,517

(1,403)

(5,232)

(206)

Increase (Decrease) in Stockholders' Equity

Net loss (income)

2,187

Other comprehensive loss

Shares reissuance for ESPP

Share repurchases

(44)

Equity-based awards activity, net

^[1]

Issuance of common stock

Common stock dividends

^[2]

(320)

Ending balance at Dec. 31, 2021

$ 3,600

$ 4

$ 8,531

$ 464

$ (5,273)

$ (126)

[1]	Includes $(9) million, $(27) million and $(36) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the years ended December 31, 2021, 2020 and 2019, respectively
[2]	Dividends per common share were $1.30, $1.20 and $0.12 for each of the years ended December 31,2021, 2020 and 2019, respectively

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Shares purchased in lieu of tax withholding (in shares)	(9)	(27)	(36)
Dividends paid per share (in usd per share)	$ 1.30	$ 1.20	$ 0.12

Nature of Business	12 Months Ended
Nature of Business	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of Business General NRG Energy, Inc., or NRG or the Company, is a consumer services company built on dynamic retail brands. NRG brings the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. NRG sells power, natural gas, home and power services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy. The Company has a customer base that includes approximately 6 million Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of generation. On January 5, 2021, the Company acquired Direct Energy, which had been a North American subsidiary of Centrica. 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 increases NRG's retail portfolio by over 3 million customers and complements its integrated model. It also broadens the Company's presence in the Northeast and into states and locales where it does not currently operate, supporting NRG's objective to diversify its business. See Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for further discussion of the acquisition of Direct Energy. On December 1, 2021, the Company sold approximately 4,850 MWs of fossil generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners. NRG received $623 million of net proceeds, after purchase price adjustments pursuant to the terms of the Purchase and Sale Agreement entered into on February 28, 2021. As part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April 2025. During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released, leading the Company to announce the near-term retirement of approximately 1,600 MW of its PJM coal generating assets in June 2022. On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of those assets, Indian River Unit 4. On August 27, 2021 the Company notified PJM that it would continue operations at Indian River Unit 4 until the reliability upgrades identified by PJM were completed, provided that the unit receives a satisfactory and compensatory reliability must run arrangement. See Item 15 — Note 11, Asset Impairments, to the Consolidated Financial Statements for further discussion. The Company is continuing to evaluate the viability of the remaining PJM generating assets. The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus. The Company's business is segmented as follows: •Texas, which includes all activity related to customer, plant and market operations in Texas; •East, which includes all activity related to customer, plant and market operations in the East; •West/Services/Other, which includes the following assets and activities: (i) all activity related to plant and market operations in the West and Canada, (ii) the Services businesses (iii) activity related to the Cottonwood facility, (iv) the remaining renewables activity, including the Company’s equity method investment in Ivanpah Master Holdings, LLC, and (v) activity related to the Company’s equity method investment for the Gladstone power plant in Australia; and •Corporate activities.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The Company's consolidated financial statements have been prepared in accordance with 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.

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 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. Though some amounts are segregated into separate accounts, not all funds are contractually restricted. Based on the Company's intention, these funds are not available for the payment of general corporate obligations; however, they are available for liquidity management. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.

Winter Storm Uri Uplift Securitization Proceeds

The Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.

In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement methodology. The Company accounted for the proceeds we will receive by analogy to the contribution model within ASC 958-605, Not-for-Profit Entities- Revenue Recognition and the grant model within IAS 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to expenses in the consolidated statements of operations in the annual period for which the proceeds are intended to compensate. The Company expects to receive proceeds of $689 million from ERCOT in the second quarter of 2022 and we concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received are determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $2.1 billion funding approved in the DOO. The associated expense reduction is reflected in Cost of operations within our consolidated statements of operations as that is where the initial costs which are being compensated for were recorded.

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, 2021:


	Year Ended December 31,
(In millions)	2021		2020
Beginning balance	$	67	$	43
Acquired balance from Direct Energy	112		—
Provision for credit losses(a)	698		108
Write-offs	(224)		(101)
Recoveries collected	30		17
Ending balance(a)	$	683	$	67

(a)Includes bilateral finance hedging risk of $403 million accounted for under ASC 815

The increase in the provision for credit losses during the year ended December 31, 2021, compared to 2020 was primarily due to the impacts of Winter Storm Uri on bilateral finance hedging risk of $403 million, counterparty credit risk of $126 million and ERCOT default shortfall payments of $67 million.

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)	2021		2020		2019
Cash and cash equivalents	$	250	$	3,905	$	345
Funds deposited by counterparties	845		19		32
Restricted cash	15		6		8
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$	1,110	$	3,930	$	385

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use.

Inventory

Inventory is valued at the lower of weighted average cost or market, and consists principally of natural gas, fuel oil, coal, spare parts and finished goods. The Company removes natural gas inventory in the delivery of goods to customers and as they are used in the production of electricity or steam. The Company removes fuel oil and coal inventories as they are used in the production of electricity. 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 natural gas, fuel oil, coal and spare parts costs in the ordinary course of business. Inventory is valued at the lower of cost or net realizable value with cost being determined on a first in first out basis for finished goods and weighted average cost method for all other inventories. 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, 2021, 2020 and 2019, was $2 million, $2 million and $3 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 emission allowances, customer and supply contracts, customer relationships, marketing partnerships, trade names 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, 2021 and 2020, the Company had accumulated amortization related to its intangible assets of $1.6 billion and $1.4 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 740 and as discussed further in Note 20, 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 and Emission Credit Amortization

Assets and liabilities recognized through acquisitions related to the purchase and sale of energy and energy-related products in future periods for which the fair value has been determined to be significantly less or more than market are amortized to operating revenues or cost of operations over the term of each underlying contract based on actual generation and/or contracted volumes.

Emission credits represent the right to generate a specified amount of emissions, including sulfur dioxide, nitrogen oxides and carbon dioxide, over a compliance period. Emission credits held for use are amortized to cost of operations based on the weighted average cost of the allowances held.

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.

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, 2021, 2020 and 2019, the Company's revenues and cost of operations included gross receipts taxes of $184 million, $107 million and $109 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.

Cost of Operations

Cost of operations includes cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization, operations and maintenance, and other cost of operations.

Cost of Fuel, Purchased Energy and Other Cost of Sales

Cost of fuel is primarily the costs associated with procurement, transportation and storage of natural gas, oil and coal to operate the generation portfolio, which is expensed as the fuel is consumed. Purchased energy primarily relates to purchases to supply the Company's customer base, which includes spot market purchases, as well as contracts of various quantities and durations, including renewable purchased power agreements under PPAs with third-party developers, which are accounted for as NPNS (see further discussion in Derivative Financial Instruments below). Other cost of sales primarily consists of TDSP expenses.

The cost of fuel is based on actual and estimated fuel usage for the applicable reporting period. The cost to deliver energy and related services to customers is based on actual and estimated supply volumes for the applicable reporting period. A portion of the cost of energy, $189 million, $98 million and $103 million as of December 31, 2021, 2020 and 2019, 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 Instruments

The Company accounts for derivative instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value and changes in fair value in earnings, unless they qualify for the NPNS exception. The Company's primary derivative instruments are power and natural gas purchase or sales contracts, fuels purchase contracts and other energy related commodities used to mitigate variability in earnings due to fluctuation in market prices. In addition, in order to mitigate foreign exchange risk associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.

As of December 31, 2021 and 2020 the Company did not have derivative instruments that were designated as cash flow or fair value or hedge.

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 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 instruments are recognized in earnings.

Mark-to-Market for Economic Hedging Activities

NRG enters into derivative instruments to manage price and delivery risk, optimize physical and contractual assets in the portfolio and manage working capital requirements. The mark-to-market for economic hedging activities are recognized to cost of operations during the reporting period.

Operations and Maintenance and Other Cost of Operations

Operations and maintenance costs include major and other routine preventative (planned outage) and corrective (forced outage) maintenance activities to ensure the safe and reliable operation of the Company's generation portfolio in compliance with all local, state and federal requirements. Operations and maintenance costs are also costs associated with retaining and maintaining the Company's customer base, such as call center support, portfolio maintenance and data analytics. Other cost of operations primarily includes gross receipts taxes, insurance, property taxes and asset retirement obligation expense.

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, 2021, 2020 and 2019, amounts recognized as foreign currency transaction gains/(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2021, 2020 and 2019 were $(8) million, $(2) 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 14, 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, which was the Company's last remaining tax equity arrangement.

Redeemable Noncontrolling Interest

The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2020 and 2019.


	(In millions)







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	$	—

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, 2021, 2020 and 2019 were $109 million, $74 million and $66 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 Estimates

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

In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Reclassifications

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

Recent Accounting Developments - Guidance Adopted in 2021

ASU 2019-12 — In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, or ASU 2019-12, to simplify various aspects related to accounting for income taxes. The guidance in ASU 2019-12 amends the general principles in Topic 740 to eliminate certain exceptions for recognizing deferred taxes for investment, performing intraperiod allocation and calculating income taxes in interim periods. This ASU also includes guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. The Company adopted the amendments effective January 1, 2021 using the prospective approach. The adoption did not have a material impact on the Company's results of operations, statements of cash flows, or statement of financial position.

ASU 2021-10 — In November 2021, the FASB issued ASU 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance, which requires additional disclosures for transactions with a government accounted for by applying a grant or contribution model by analogy, including: (i) the nature of the transactions and the related accounting policy used to account for the transactions; (ii) the line items on the balance sheet and income statement that are affected by the transactions, and the amounts applicable to each financial statement line item; and (iii) significant terms and conditions of the transactions, including commitments and contingencies. The amendments were applied prospectively to all transactions within the scope of the amendments. Early application of the new standard is permitted and the effect of the new standard only impacted the Company’s financial statement disclosures.

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 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. The Company adopted this standard on January 1, 2022 using the modified retrospective approach. As a result of the provisions of the amended guidance, the Company estimates a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings, and a $14 million decrease to long-term deferred tax liabilities. The Company does not expect the adoptions of ASU 2020-06 to have a material impact on its statement of operations, statements of cash flows or earnings per share amounts.

ASU 2021-08 — In October 2021, the FASB issued ASU No. 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers, or ASU 2021-08. Under current GAAP, an acquirer generally recognizes assets acquired and liabilities assumed in a business combination, including contract assets and contract liabilities arising from revenue contracts with customers and other similar contracts that are accounted for in accordance with ASC 606, Revenue from Contracts with Customers, or ASC 606, at fair value on the acquisition date. ASU 2021-08 requires that an entity recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with ASC 606. At the acquisition date, an acquirer should account for the related revenue contracts in accordance with ASC 606 as if it had originated the contracts, which should generally result in an acquirer recognizing and measuring the acquired contract assets and contract liabilities consistent with how they were recognized and measured in the acquiree’s financial statements. This update also provides certain practical expedients for acquirers when recognizing and measuring acquired contract assets and contract liabilities from revenue contracts in a business combination. The amendments in this update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years and should be applied prospectively to business combinations occurring on or after the effective date of the amendments. Early adoption is permitted, including adoption in an interim period. Adoption during an interim period requires retrospective application to all business combinations for which the acquisition date occurs on or after the beginning of the fiscal year that includes the interim period of early application and prospectively to all business combinations that occur on or after the date of initial application. The Company does not expect the adoption of ASU 2021-08 to have a material impact on the consolidated financial statements and disclosures.

Revenue Recognition

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Revenue Recognition

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.

Ancillary revenues, included in Other revenue, are recognized over time as the obligation is fulfilled, using the output method for measuring progress of satisfaction of performance obligations.

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, 2021, estimated future fixed fee performance obligations are $258 million, $48 million and $1 million for fiscal years 2022, 2023 and 2024, 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.

Disaggregated Revenue

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the years ended December 31, 2021, 2020 and 2019:


	For the Year Ended December 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue
Home(a)	$	5,665	$	1,959	$	2,053	$	(1)	$	9,676
Business	2,745		9,903		1,237		—		13,885
Total retail revenue	8,410		11,862		3,290		(1)		23,561
Energy revenue(c)	329		508		371		7		1,215
Capacity revenue(c)	—		718		57		—		775
Mark-to-market for economic hedging activities(d)	(3)		(88)		(86)		13		(164)
Contract amortization	—		(26)		(4)		—		(30)
Other revenue(b)(c)	1,557		59		25		(9)		1,632
Total operating revenue	10,293		13,033		3,653		10		26,989
Less: Lease revenue	—		1		7		—		8
Less: Realized and unrealized ASC 815 revenue	130		184		(96)		16		234
Less: Contract amortization	—		(26)		(4)		—		(30)
Total revenue from contracts with customers	$	10,163	$	12,874	$	3,746	$	(6)	$	26,777
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.3 billion driven by high pricing during Winter Storm Uri
(c) 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/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	131	$	2	$	3	$	136
Capacity revenue	—		149		—		—		149
Other revenue	133		(8)		(12)		—		113
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	For the Year Ended December 31, 2020
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue
Home(a)	$	5,027	$	1,210	$	96	$	(2)	$	6,331
Business	1,034		95		—		—		1,129
Total retail revenue	6,061		1,305		96		(2)		7,460
Energy revenue(b)	24		183		333		(1)		539
Capacity revenue(b)	—		620		61		(1)		680
Mark-to-market for economic hedging activities(c)	2		88		(3)		8		95

Other revenue(b)	222		62		43		(8)		319
Total operating revenue	6,309		2,258		530		(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	$	1,943	$	475	$	(7)	$	8,690
(a) Home includes Services
(b) 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/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	67	$	43	$	(5)	$	105
Capacity revenue	—		156		—		—		156
Other revenue	28		3		(2)		—		29
(c) 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/Services/Other		Corporate/Eliminations		Total
Retail revenue
Home(a)	$	5,027	$	1,173	$	57	$	(3)	$	6,254
Business	1,205		74		—		—		1,279
Total retail revenue	6,232		1,247		57		(3)		7,533
Energy revenue(b)	529		322		318		—		1,169
Capacity revenue(b)	—		664		36		—		700
Mark-to-market for economic hedging activities(c)	47		(29)		16		(1)		33

Other revenue(b)	261		58		70		(3)		386
Total operating revenue	7,069		2,262		497		(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	$	2,078	$	411	$	(5)	$	7,991
(a) Home includes Services
(b) 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/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	1,459	$	98	$	39	$	(1)	$	1,595
Capacity revenue	—		109		—		—		109
Other revenue	56		5		12		—		73
(c) 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, 2021 and 2020:


(In millions)	December 31, 2021		December 31, 2020
Deferred customer acquisition costs	$	133	$	113

Accounts receivable, net - Contracts with customers	3,057		866
Accounts receivable, net - Derivative instruments	182		33
Accounts receivable, net - Affiliate	6		5
Total accounts receivable, net	$	3,245	$	904

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,574	$	393

Deferred revenues (a)	$	227	$	60

(a) Deferred revenues from contracts with customers for the years ended December 31, 2021 and 2020 were approximately $224 million and $31 million, respectively

The revenue recognized from contracts with customers during the years ended December 31, 2021 and 2020 relating to the deferred revenue balance at the beginning of each period was $23 million and $13 million, respectively. The change in deferred revenue balances during the years ended December 31, 2021 and 2020 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.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

+ Details

Acquisitions, Discontinued Operations and Dispositions

12 Months Ended

Dec. 31, 2021

Discontinued Operations and Disposal Groups [Abstract]

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, which had been 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 final purchase price adjustment resulted in additional payment of $22 million, which was paid in December 2021.

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)
Available on Acquisition Closing Date
Revolving Credit Facility commitment increase	$	802
Revolving Credit Facility new tranche	273
Facility agreement in connection with the sale of pre-capitalized trust securities	874
Available as of December 31, 2020
Credit default swap facility	150
Revolving accounts receivable financing facility	750
Repurchase facility	75
Bilateral letter of credit facilities	475
Total Increases to Liquidity and Collateral Facilities	$	3,399

For further discussion see Note 13, Long-term Debt and Finance Leases.

Acquisition costs of $25 million and $17 million for the years ended December 31, 2021 and 2020, respectively, are included in acquisition-related transaction and integration costs in the Company's consolidated statement of operations.

The acquisition has been recorded as a business combination under ASC 805 with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The purchase price is allocated as follows:


	(In millions)
Current Assets
Cash and cash equivalents	$	152
Funds deposited by counterparties	21
Restricted cash	9
Accounts receivable, net	1,802
Inventory	106
Derivative instruments	1,014
Cash collateral paid in support of energy risk management activities	233
Prepayments and other current assets	173
Total current assets	3,510
Property, plant and equipment, net	151
Other Assets
Goodwill(a)	1,250
Intangible assets, net:
Customer relationships(b)	1,277
Customer and supply contracts(b)	610
Trade names(b)	310
Renewable energy credits	124
Total intangible assets, net	2,321
Derivative instruments	531
Other non-current assets	31
Total other assets	4,133
Total Assets	$	7,794


	(In millions)
Current Liabilities
Accounts payable	$	1,116
Derivative instruments	1,266
Cash collateral received in support of energy risk management activities	21
Accrued expenses and other current liabilities	670
Total current liabilities	3,073
Other Liabilities
Derivative instruments	562
Deferred income taxes	320
Other non-current liabilities	115
Total other liabilities	997
Total Liabilities	$	4,070

Direct Energy Purchase Price	$	3,724

(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. Goodwill was allocated to the Texas, East, and West/Services/Other segments of $427 million, $648 million , and $175 million, respectively. Goodwill expected to be deductible for tax purposes is $322 million

(b)The weighted average amortization period for total amortizable intangible assets is 12 years

Measurement Period Adjustments

The following measurement period adjustments were recognized during the quarter ended December 31, 2021:


	(In millions)
Assets
Prepayments and other current assets	$	(10)

Goodwill	(7)

Total decrease in assets	$	(17)
Liabilities
Accounts payable	$	(4)
Accrued expenses and other current liabilities	(20)
Deferred income taxes	(18)

Total decrease in liabilities	$	(42)
Net measurement period adjustments	$	25

The measurement period adjustments are attributable primarily to refinement of the underlying assumptions used to estimate the fair value of assets acquired and liabilities assumed as more information was obtained about facts and circumstances that existed as of the Acquisition Closing Date.

Fair Value Measurement of Intangible Assets

The fair values of intangible assets as of the Acquisition Closing Date were measured primarily based on significant inputs that are observable and unobservable in the market and thus represent Level 2 and Level 3 measurements, respectively. Significant inputs were as follows:

Customer relationships — Customer relationships, reflective of Direct Energy’s customer base, were valued using an excess earning method of the income approach. Under this approach, the Company estimated the present value of expected future cash flows resulting from existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce and trade names) utilized in the business, discounted at an independent power producer peer group’s weighted average cost of capital. The customer relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows. The weighted average amortization period is 12 years.

Customer and supply contracts — The fair value of in-market and out-of-market customer and supply contracts were estimated based on contractual terms compared to market prices as of the Acquisition Closing Date. The majority of the contracts were valued using prices provided by external sources, primarily price quotations available through broker or over-the-counter and online exchanges. For contracts for which external sources or observable market quotes were not available, these values were based on valuation techniques including, but not limited to, internal models based on fundamental analysis of the market and extrapolation of the observable market data with similar characteristics. In addition, the Company applied a credit reserve to reflect credit risk, which is calculated based on published default probabilities. The customer and supply contracts are amortized to revenue and cost of operations, respectively, based upon the fair market value, as of the acquisition date, for each delivery month. The weighted average amortization period is 14 years.

Trade names — Trade names were valued using a "relief from royalty" method of the income approach. Under this approach, the fair value is estimated to be the present value of royalties saved because NRG owns the intangible asset and therefore does not have to pay a royalty for its use. The trade names are amortized to depreciation and amortization, on a straight line basis, over a weighted average amortization period of 15 years.

Renewable energy credits — Renewable energy credits were valued based on the market prices as of the Acquisition Closing Date. Renewable energy credits are retired, as required, for the applicable compliance period. They are expensed to cost of operations based on customer usage.

Fair Value Measurement of Derivative Assets and Liabilities

The fair values of derivatives assets and liabilities as of the Acquisition Closing Date were as follows:


	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Derivatives assets	$	1,545	$	155	$	1,272	$	118
Derivatives liabilities	1,828		207		1,489		132

Refer to Note 5, Fair Value of Financial Instruments for discussion on derivative fair value measurements.

Supplemental Information

For the Year Ended December 31, 2021 Direct Energy contributed revenue and income before income taxes of $15.6 billion and $2.4 billion, respectively.

Supplemental Unaudited Pro Forma Financial Information

The following table provides unaudited pro forma combined financial information of NRG and Direct Energy, after giving effect to the Direct Energy acquisition and related financing transactions as if they had occurred on January 1, 2019. The pro forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project future operating results or indicative of what our financial performance would have been had the transactions occurred on the date assumed. No effect has been given to operating synergies.


	For the Year Ended December 31,
(In millions)	2021		2020		2019
Total operating revenues	$	26,987	$	21,326	$	23,673
Income from continuing operations	2,225		471		3,623

Amounts above reflect certain pro forma adjustments that were directly attributable to the Direct Energy acquisition. These adjustments include the following:

(i) Income statement effects of fair value adjustments based on the purchase price allocation including amortization of intangible assets, depreciation of property, plant and equipment and lease expense.

(ii) Interest expense assumes the financing transactions directly attributable to the Direct Energy acquisition occurred on January 1, 2019.

(iii) Removal of Direct Energy historical interest expense associated with related party notes receivable/payable between Direct Energy and Centrica and its subsidiaries, as those notes are assumed to be repaid as of January 1, 2019.

(iv) Elimination of transactions between NRG and Direct Energy.

(v) Adjustments to reflect all acquisition costs occurring during the year ended December 31, 2019.

(vi) Tax effects of pro forma adjustments on all periods presented and shifting the recognition of one time tax benefits resulting from the acquisition from the year ended December 31, 2021 to the year ended December 31, 2019.

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

Dispositions

Sale of 4,850 MW of Fossil generating assets

On December 1, 2021, the Company closed the previously announced sale of approximately 4,850 MWs of fossil generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners. Proceeds of $760 million were reduced by working capital and other adjustments of $137 million, resulting in net proceeds of $623 million. The Company recorded a gain of $210 million from the sale, which includes the $39 million indemnification liability recorded as discussed below. As part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April 2025.

As part of the agreement to sell the fossil generating assets, NRG has agreed to indemnify Generation Bridge for certain future environmental compliance costs up to $39 million. The indemnity term will expire on December 1, 2028. The Company has recorded the liability within accrued expenses and other current liabilities and other non-current liabilities.

Sale of Agua Caliente

On February 3, 2021, the Company closed on the sale of its 35% ownership in the Agua Caliente solar project to Clearway Energy, Inc. for $202 million. NRG recognized a gain on the sale of $17 million, including cash disposed of $7 million.

Sale of 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, 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.

Company completed other asset sales for cash proceeds of $12 million and $15 million during the years ended December 31, 2021 and 2020, respectively.

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 represented a strategic shift in the business in which NRG operates. 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 1,177 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 for the year ended December 31, 2019 were as follows:


	(In millions)
Operating revenues	$	31
Operating costs and expenses	(23)



Gain from operations of discontinued components	8
Gain on disposal of discontinued operations, net of tax	20
Gain from discontinued operations, including disposal, net of tax	$	28

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. 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-year extensions. As a result of the transaction, additional commitments related to the project totaled $23 million as of December 31, 2021 and December 31, 2020.

Summarized results of NRG Yield, Inc. and Renewables Platform and Carlsbad discontinued operations for the year ended December 31, 2019 were as follows:



	(In millions)
Operating revenues	$	19
Operating costs and expenses	(9)

Other expenses	(5)


Gain/(loss) from discontinued operations, net of tax	5
Gain/(loss) on disposal of discontinued operations, net of tax	265
Income/(expense) from California property tax indemnification	22
Income/(expense) from other commitments, indemnification and fees	4
Income/(loss) on disposal of discontinued operations, net of tax	291
Income/(loss) from discontinued operations, net of tax	$	296

GenOn

On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Texas 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 Texas Bankruptcy Court; and accordingly, NRG deconsolidated GenOn and its subsidiaries for financial reporting purposes as of such date. For the Year Ended December 31, 2019 NRG recorded $3 million loss from discontinued operations, net of tax for GenOn results of operations.

Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

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 paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

The estimated carrying value and fair value of the Company's long-term debt, including current portion, is as follows:


	As of December 31,
	2021				2020
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value



Long-term debt, including current portion (a)	$	8,040	$	8,327	$	8,781	$	9,446

(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.

Fair Value Accounting under ASC 820

ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.

•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forward contracts.

•Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.

Recurring Fair Value Measurements

Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.

The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:


	As of December 31, 2021
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	32	$	15	$	17	$	—

Nuclear trust fund investments:
Cash and cash equivalents	33		33		—		—
U.S. government and federal agency obligations	112		111		1		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	44		—		44		—
Corporate debt securities	122		—		122		—
Equity securities	494		494		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Foreign exchange contracts	1		—		1		—
Commodity contracts	7,139		981		5,701		457


Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	99
Equity securities (classified within other non-current assets)	7
Total assets	$	8,188	$	1,635	$	5,990	$	457
Derivative liabilities:
Foreign exchange contracts	$	1	$	—	$	1	$	—
Commodity contracts	$	4,798	$	626	$	4,008	$	164

Total liabilities	$	4,799	$	626	$	4,009	$	164


	As of December 31, 2020
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current or 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 (classified within other non-current assets):
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 (classified within other non-current assets)	8
Total assets	$	1,745	$	597	$	914	$	139
Derivative liabilities:
Commodity contracts	$	884	$	86	$	643	$	155

Total liabilities	$	884	$	86	$	643	$	155

The following tables reconcile, for the years ended December 31, 2021 and 2020, 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, 2021
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
(In millions)	Derivatives (a)
Beginning balance as of January 1, 2021	$	(16)
Contracts added from Direct Energy acquisition	(15)

Total gains realized/unrealized included in earnings	145


Purchases	93

Transfers into Level 3 (b)	71
Transfers out of Level 3 (b)	15
Ending balance as of December 31, 2021	$	293
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, 2021	$	120

(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, 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

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 6% of derivative assets and 3% 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 foreign exchange contracts and 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 foreign exchange contracts, 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, 2021 the credit reserve resulted in a $11 million decrease primarily within cost of operations. As of December 31, 2020 the credit reserve resulted in $2 million increase primarily within cost of operations.

The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2021, 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 natural gas and power executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid natural gas and 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, 2021 and 2020:


	Significant Unobservable Inputs
	December 31, 2021
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Natural Gas Contracts	$	16	$	1	Discounted Cash Flow	Forward Market Price (per MMBtu)	$	3	$	40	$	15
Power Contracts	392		121		Discounted Cash Flow	Forward Market Price (per MWh)	3		212		35
FTRs	49		42		Discounted Cash Flow	Auction Prices (per MWh)	(122)		43		0
	$	457	$	164


	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

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2021 and 2020:

Significant Unobservable Input

Position

Change In Input

Impact on Fair Value Measurement

Forward Market Price Natural Gas/ Power

Buy

Increase/(Decrease)

Higher/(Lower)

Forward Market Price Natural Gas/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, 2021, the Company recorded $291 million of cash collateral posted and $845 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, 2021, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $2.2 billion and NRG held collateral (cash and letters of credit) against those positions of $598 million, resulting in a net exposure of $1.6 billion. 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 87% of the Company's exposure before collateral is expected to roll off by the end of 2023. 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	67	%
Financial institutions	33


Total	100	%


Category	Net Exposure (a) (b) (% of Total)
Investment grade	55	%
Non-Investment grade/Non-Rated	45

Total	100	%

(a)Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices

(b)The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts

The Company currently has no exposure to wholesale counterparties in excess of 10% of the total net exposure discussed above as of December 31, 2021. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

During Winter Storm Uri, the Company experienced nonperformance by a counterparty in one of its bilateral financial hedging transactions, resulting in exposure of $403 million. The Company is pursuing all means available to enforce its rights under this transaction but, given the size of the exposure, cannot determine with certainty what the amount of its ultimate recovery will be. The full exposure was recorded as a provision for credit losses during the year ended December 31, 2021.

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, NYMEX and Nodal. 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, 2021, aggregate credit risk exposure managed by NRG to these counterparties was approximately $1.1 billion for the next five years.

Retail Customer Credit Risk

The Company is exposed to retail credit risk through the Company's retail electricity and gas providers, which serve Home and Business customers. 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, 2021, the Company's retail customer credit exposure to Home and Business 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 $698 million, $108 million, and $95 million for the years ending December 31, 2021, 2020, and 2019, respectively. As a result of Winter Storm Uri, the Company incurred additional credit losses from Business customers primarily due to a segment of customers whose contracts included a pass through of wholesale power prices which were significantly escalated during the storm and from customers who failed to meet their obligations in ERCOT load curtailment programs.

- Definition

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

+ References + Details

Accounting for Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

ASC 815 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. The Company may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings.

For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG's energy related commodity contracts, foreign exchange 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 and gas 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 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 and gas 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, 2021, 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 2036;

•Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2024;

•Other energy derivatives instruments extending through 2029.

Also, as of December 31, 2021, 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 2036;

•Load-following forward natural gas sale contracts extending through 2032;

•Power tolling contracts through 2038;

•Coal purchase contracts through 2023;

•Power transmission contracts through 2025;

•Natural gas transportation contracts through 2034;

•Natural gas storage agreements through 2025; and

•Coal transportation contracts through 2029.

Interest Rate Swaps

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.

Foreign Exchange Contracts

In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements through 2025.

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, 2021 and 2020. 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, 2021	December 31, 2020
Emissions	Short Ton	1	1
Renewables Energy Certificates	Certificates	13	5
Coal	Short Ton	19	2
Natural Gas	MMBtu	813	(286)
Oil	Barrels	1	—
Power	MWh	185	57
Capacity	MW/Day	—	(1)


Foreign Exchange	Dollars	279	—

The increase in positions is primarily the result of Direct Energy acquisition.

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, 2021		December 31, 2020		December 31, 2021		December 31, 2020






Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Foreign exchange contracts - current	$	—	$	—	$	1	$	—
Foreign exchange contracts - long-term	1		—		—		—

Commodity contracts- current	4,613		560		3,386		499
Commodity contracts- long-term	2,526		261		1,412		385

Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	7,140	$	821	$	4,799	$	884

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, 2021
Foreign exchange contracts:
Derivative assets	$	1	$	(1)	$	—	$	—
Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	$	—	$	—	$	—	$	—
Commodity contracts:
Derivative assets	$	7,139	$	(4,440)	$	(831)	$	1,868
Derivative liabilities	(4,798)		4,440		17		(341)
Total commodity contracts	$	2,341	$	—	$	(814)	$	1,527






Total derivative instruments	$	2,341	$	—	$	(814)	$	1,527


	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)

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 results 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 foreign exchange and 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)	2021		2020		2019
Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(41)	$	(55)	$	(68)
Reversal of acquired loss positions related to economic hedges	256		4		6
Net unrealized gains/(losses) on open positions related to economic hedges	2,501		(68)		42
Total unrealized mark-to-market gains/(losses) for economic hedging activities	2,716		(119)		(20)
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity	(18)		(20)		(11)
Reversal of acquired (gain) positions related to trading activity	(1)		—		—

Net unrealized (losses)/gains on open positions related to trading activity	(13)		15		31
Total unrealized mark-to-market (losses)/gains for trading activity	(32)		(5)		20
Total unrealized gains/(losses)	$	2,684	$	(124)	$	—


	Year Ended December 31,
(In millions)	2021		2020		2019
Unrealized (losses)/gains included in operating - commodities	$	(196)	$	90	$	53
Unrealized gains/(losses) included in cost of operations- commodities	2,880		(214)		(53)
Total impact to statement of operations- commodities	$	2,684	$	(124)	$	—
Total impact to statement of operations — interest rate contracts	$	—	$	—	$	(38)

The reversals of acquired loss/(gain) positions were valued based upon the forward prices on the acquisition date. 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.

The gain from open economic hedge positions of $2.5 billion for the year ended December 31, 2021 was primarily the result of an increase in value of forward positions as a result of increases in natural gas and power prices.

The loss from open economic hedge positions of $68 million for the year ended December 31, 2020 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 gain from open economic hedge positions of $42 million for the year ended December 31, 2019 was 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 and trading agreements contain provisions that entitle the counterparty to demand that the Company post additional collateral if the counterparty determines that there has been deterioration in the Company's 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. In addition, as a result of the acquisition of Direct Energy from Centrica, certain of the Company’s agreements as of December 31, 2021, were still supported by credit support posted by Centrica, and as a result could require the Company to post collateral upon a deterioration or downgrade of Centrica. The collateral potentially required for contracts with adequate assurance clauses that are in net liability positions as of December 31, 2021 was $1.0 billion. 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 $70 million as of December 31, 2021. In the event of a downgrade in the Company's credit rating and 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, 2021.

See Note 5, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.

Nuclear Decommissioning Trust Fund

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

Nuclear Decommissioning Trust Fund

NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rates charged to rate payers all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities.

NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, or ASC 980, because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.

The following table summarizes the aggregate fair values and unrealized gains and losses for the securities held in the trust funds, as well as information about the contractual maturities of those securities.


	As of December 31, 2021							As of December 31, 2020
(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	$	33	$	—	$	—	—	$	23	$	—	$	—	—
U.S. government and federal agency obligations	112		5		1		10	70		6		—		10
Federal agency mortgage-backed securities	100		2		—		25	89		4		—		24
Commercial mortgage-backed securities	44		1		—		27	36		2		—		27
Corporate debt securities	122		7		1		14	144		13		—		12
Equity securities	593		456		—		—	521		372		—		—
Foreign government fixed income securities	4		—		—		13	7		1		—		10
Total	$	1,008	$	471	$	2		$	890	$	398	$	—

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)	2021		2020		2019
Realized gains	$	47	$	34	$	18
Realized (losses)	(9)		(13)		(9)
Proceeds from sale of securities	710		439		381

Inventory

12 Months Ended

Dec. 31, 2021

Inventory Disclosure [Abstract]

Inventory

Inventory consisted of:


	As of December 31,
(In millions)	2021		2020
Fuel oil	$	8	$	37
Coal	83		73
Natural gas	206		22
Spare parts and finished goods	201		195
Total Inventory	$	498	$	327

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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


	As of December 31,				Depreciable
(In millions)	2021		2020		Lives
Facilities and equipment	$	1,742	$	3,365	1-40 years
Land and improvements	271		329
Nuclear fuel	222		239		5 years
Hardware and office equipment and furnishings	637		453		2-10 years
Construction in progress	124		97
Total property, plant, and equipment	2,996		4,483
Accumulated depreciation	(1,308)		(1,936)
Net property, plant, and equipment	$	1,688	$	2,547

The Company recorded long-lived asset impairments during the years ended December 31, 2021 and 2020, as further described in Note 11, Asset Impairments. Depreciation expense of property, plant and equipment recorded during the years ended December 31, 2021, 2020 and 2019 was $384 million, $295 million and $271 million, respectively.

Leases

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Leases

The Company leases generating facilities, land, office and equipment, railcars, fleet vehicles 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, as permitted by ASC 842, 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. 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.

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:


	For the Year Ended December 31,
(In millions)	2021		2020		2019
Finance lease cost	$	4	$	3	$	—


Operating lease cost	91		100		109
Short-term lease cost	3		3		3
Variable lease cost	9		6		6
Sublease income	(2)		(17)		(17)
Total lease cost	$	105	$	95	$	101

Other information:


	For the Year Ended December 31,
(In millions)	2021		2020		2019

Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	102	$	101	$	104

Financing cash flows from finance leases	6		1		—
Right-of-use assets obtained in exchange for new finance lease liabilities	16		5		—
Right-of-use assets obtained in exchange for new operating lease liabilities	47		4		215

Lease Term and Discount Rate for leases:


	December 31, 2021		December 31, 2020
Finance leases:
Weighted average remaining lease term (in years)	3.6		1.1
Weighted average discount rate	2.46	%	4.79	%

Operating leases:
Weighted average remaining lease term (in years)	4.7		5.3
Weighted average discount rate	5.44	%	5.63	%

As of December 31, 2021, annual payments based on the maturities of NRG's operating leases are expected to be as follows:


	In millions
2022	$	96
2023	89
2024	76
2025	52
2026	11
Thereafter	48
Total undiscounted lease payments	$	372
Less: present value adjustment	(55)
Total discounted lease payments	$	317

Asset Impairments	12 Months Ended
Asset Impairments	Dec. 31, 2021
Asset Impairment Charges [Abstract]
Asset Impairments	Asset Impairments 2021 Impairment Losses During the fourth quarter of 2021, the Company completed its annual budget and analyzed the corresponding impact on estimated cash flows associated with its long-lived assets. 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. Joliet —The Company recognized an impairment loss of $213 million in the East segment as a result of changes in the long-term outlook of the Joliet facility prompted by market conditions and an assessment of various alternatives for the long-term operational landscape of the facility including the impact of the CEJA in Illinois, which concluded with the annual budget process. Other Impairments — The Company additionally recorded impairment losses of $16 million and $9 million related to various power plants in the East and West/Service/Other segments, respectively. The Company also recorded the following impairment in 2021 based on a specific triggering event that occurred using the same methodology previously discussed: PJM Asset Impairments — During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released leading the Company to announce the near-term retirement of a significant portion of its PJM coal generating assets in June 2022. The Company considered the decline in PJM capacity prices and the near-term retirement dates of certain assets to be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with Midwest Generation. Impairment losses of $271 million and $35 million were recorded in the East segment on the PJM generating assets and Midwest Generation goodwill, respectively. 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/Services/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/Services/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.

Goodwill and Other Intangibles

12 Months Ended

Dec. 31, 2021

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangibles

Goodwill

The table below presents the changes of goodwill for the year ended December 31, 2021 based on the Company's reportable segments. Goodwill did not change during the year ended December 31, 2020.


(in millions)	Texas		East		West/Services/Other		Total
Balance as of January 1, 2021	$	324	$	240	$	15	$	579
Goodwill resulted from the acquisition of Direct Energy	427		648		175		1,250
Impairment losses	—		(35)		—		(35)
Foreign currency translation	—		—		1		1
Balance as of December 31, 2021	$	751	$	853	$	191	$	1,795

Intangible Assets

The Company's intangible assets as of December 31, 2021, primarily reflect intangible assets established with the acquisitions of various companies, including Direct Energy, Stream Energy, 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.

•Customer and supply contracts — These intangibles include the fair value at the acquisition date of in-market and out-of-market customer and supply contracts from the acquisition of Direct Energy and are amortized to revenue and cost of operations, respectively, based upon the fair market value, as of the acquisition date, for each delivery month. It also included 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 and are amortized based on the expected delivery under the respective contracts.

•Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base from the acquisition of Direct Energy and other acquisitions. 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 — These intangibles primarily include renewable energy credits. 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. It also includes in-market nuclear fuel contracts established from the Texas Genco acquisition in 2006 which are amortized to cost of operations over expected volumes over the life of each contract, costs to extend the operating license for STP Units 1 and 2 and intellectual property related to Goal Zero which are amortized to depreciation and amortization expense.

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


(In millions)
Year Ended December 31, 2021	Emission Allowances		Customer and Supply Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other(b)		Total
January 1, 2021	$	672	$	28	$	527	$	285	$	373	$	140	$	2,025
Purchases	10		—		—		—		—		338		348
Acquisition of businesses (a)	—		610		1,308		—		310		124		2,352
Usage/Sales/Retirements	(1)		—		—		—		—		(364)		(365)
Write-off of fully amortized balances	(51)		—		(158)		—		—		(7)		(216)

Other	4		—		2		(1)		—		(2)		3
December 31, 2021	634		638		1,679		284		683		229		4,147
Less accumulated amortization	(536)		(94)		(518)		(123)		(294)		(71)		(1,636)
Net carrying amount	$	98	$	544	$	1,161	$	161	$	389	$	158	$	2,511

(a)The weighted average life of total acquired amortizable intangibles from the Direct Energy acquisition was 12 years, see Note 4 — Acquisitions, Discontinued Operations and Dispositions for weighted average life of acquired amortizable intangibles for each intangible asset type

(b)RECs are not subject to amortization and had a carrying value of $123 million


(In millions)
Year Ended December 31, 2020	Emission Allowances		Customer and Supply Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other(b)		Total
January 1, 2020	$	662	$	28	$	573	$	285	$	373	$	130	$	2,051
Purchases	25		—		—		—		—		45		70
Acquisition of businesses (a)	—		—		22		—		—		—		22
Usage/Retirements	—		—		—		—		—		(35)		(35)
Write-off of fully amortized balances	(4)		—		(70)		—		—		—		(74)
Impairment	(14)		—		—		—		—		—		(14)
Other	3		—		2		—		—		—		5
December 31, 2020	672		28		527		285		373		140		2,025
Less accumulated amortization	(563)		(28)		(349)		(99)		(247)		(71)		(1,357)
Net carrying amount	$	109	$	—	$	178	$	186	$	126	$	69	$	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

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


	Years Ended December 31,
(In millions)	2021		2020		2019
Emission allowances	$	24	$	28	$	32
Customer and supply contracts	66		12		14
Customer relationships	327		74		44
Marketing partnerships	24		24		15
Trade names	47		27		25
Other(a)	7		3		4
Total amortization	$	495	$	168	$	134

(a)For the years ended December 31, 2021, 2020 and 2019, other intangibles were amortized to depreciation and amortization expense for $3 million, $3 million and $4 million, respectively

The following table presents estimated amortization of NRG's intangible assets as of December 31, 2021 for each of the next five years:


(In millions)
Year Ended December 31,	Emission Allowances		Customer and Supply Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other		Total
2022	$	14	$	143	$	265	$	23	$	47	$	3	$	495
2023	12		120		216		23		46		4		421
2024	12		73		148		23		38		3		297
2025	11		50		110		22		32		4		229
2026	9		52		95		22		24		4		206

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, 2021 and 2020, the value of emission allowances held-for-sale was $15 million and $14 million, respectively, within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.

Long-term Debt and Finance Leases

12 Months Ended

Dec. 31, 2021

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, 2021		December 31, 2020		Interest rate %

Recourse debt:
Senior Notes, due 2026	$	—	$	1,000	7.250
Senior Notes, due 2027	375		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		500		3.375
Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	1,100		—		3.875
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		500		2.000
Senior Secured First Lien Notes, due 2027	900		900		2.450
Senior Secured First Lien Notes, due 2029	500		500		4.450

Tax-exempt bonds	466		466		1.250 - 4.750




Subtotal long-term debt (including current maturities)	8,100		8,855
Finance leases	13		4		various

Subtotal long-term debt and finance leases (including current maturities)	8,113		8,859
Less current maturities	(4)		(1)
Less debt issuance costs	(83)		(93)
Discounts	(60)		(74)
Total long-term debt and finance leases	$	7,966	$	8,691

(a)The effective interest rate was 5.34% and 5.19% for the years ended December 31, 2021 and 2020, respectively. As of the ex-dividend date of January 31, 2022, the Convertible Senior Notes were convertible at a price of $44.53, which is equivalent to a conversion rate of approximately 22.4563 shares of common stock per $1,000 principal amount. The remaining period over which the discount on the liability component would have been amortized is 3.7 years. However, the adoption of ASU 2020-06 on January 1, 2022 resulted in the elimination of the debt discount.

Debt includes the following discounts:


	As of December 31,
(In millions)	2021		2020
Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029	$	(2)	$	(2)
Convertible Senior Notes, due 2048	(58)		(72)
Total discounts	$	(60)	$	(74)

Consolidated Annual Maturities

As of December 31, 2021, annual payments based on the maturities of NRG's debt and finance leases are expected to be as follows:


	(In millions)
2022	$	4
2023	3
2024	603
2025	502
2026	—
Thereafter	7,001
Total	$	8,113

Senior Notes

Issuance of 2032 Senior Notes

On August 23, 2021, the Company issued $1.1 billion of aggregate principal amount of 3.875% senior notes due 2032. The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on February 15, 2022 until the maturity date of February 15, 2032. The 2032 Senior 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 2032 Senior Notes from and including August 15, 2026. The proceeds of the 2032 Senior Notes, along with cash on hand, were used to fund the redemption of $1.0 billion aggregate principal amount of the 7.250% Senior Notes due 2026 and $355 million aggregate principal amounts of the 6.625% Senior Notes due 2027.

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 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 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 December 2, 2027 for the 2027 Secured Notes.

Senior Note Redemptions

During the year ended December 31, 2021, the Company redeemed approximately $1.9 billion in aggregate principal amount of its Senior Notes for $1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand, as detailed in the table below. In connection with the redemptions, a $77 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $12 million.


(In millions, except percentages)	Principal Repurchased		Cash Paid(a)		Average Early Redemption Percentage
7.250% Senior Notes, due 2026	$	1,000	$	1,056	103.625	%
6.625% Senior Notes, due 2027	855		893		103.313	%
Total	$	1,855	$	1,949

(a) Includes accrued interest of $29 million for redemptions for the year ended December 31, 2021

2048 Convertible Senior Notes

The Convertible Senior 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. Prior to February 22, 2022, the Convertible Senior Notes were convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at a price of $44.89 per common share as of December 31, 2021, which is equivalent to a conversion rate of approximately 22.2761 shares of common stock per $1,000 principal amount

of Convertible Senior Notes. On February 22, 2022, the Company irrevocably elected to eliminate the right to settle conversions only in shares of the Company's common stock, such that any conversion after such date will be settled in cash or a combination of cash and the Company's common stock. As of December 31, 2020, the Convertible Senior Notes were convertible at a price of $46.24 per common share, which is equivalent to a conversion rate of approximately 21.6242 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The carrying amounts of the liability components as of December 31, 2021 and 2020 of $518 million and $503 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, 2021, NRG had the following outstanding issuances of senior notes with an early redemption feature, or Senior Notes:

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

ii.5.750% senior notes, issued December 7, 2017 and due January 15, 2028, or the 2028 Senior Notes;

iii.5.250% senior notes, issued May 24, 2019 and due June 15, 2029, or the 2029 Senior Notes;

iv.3.375% senior notes, issued December 2, 2020 and due February 15, 2029, or the 3.375% 2029 Senior Notes;

v.3.625% senior notes, issued December 2, 2020 and due February 15, 2031, or the 2031 Senior Notes; and

vi.3.875% senior notes, issued August 23, 2021 and due February 15, 2032, or the 2032 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% or 30% (depending on the series of Senior Notes) 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.

2027 Senior Notes

NRG may redeem some or all of the 2027 Senior Notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Redemption Period	Redemption Percentage
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, 2023, NRG may redeem all or a part of the 2028 Senior Notes, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus 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 Percentage
January 15, 2023 to January 14, 2024	102.875	%
January 15, 2024 to January 14, 2025	101.917	%
January 15, 2025 to January 14, 2026	100.958	%
January 15, 2026 and thereafter	100.000	%

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 of the notes redeemed, plus 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 of the notes redeemed, plus 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 of the notes redeemed, plus 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	%

2032 Senior Notes

At any time prior to August 15, 2024, NRG may redeem up to 40% of the aggregate principal amount of the 2032 Senior Notes, at a redemption price equal to 103.875% 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, 2027, NRG may redeem all or a part of the 2032 Senior Notes, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus 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 (A) the present value of (1) the redemption price of the note at February 15, 2027 (such redemption price being set forth in the table appearing below in the column “Redemption Percentage (If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)” unless the Sustainability Performance Target has been satisfied in respect of the year ended December 31, 2025 and the Company has provided confirmation thereof to the Trustee together with a related confirmation by the External Verifier by the date that is at least 15 days prior to August 15, 2026 in which case the redemption price shall be as set forth in the column “Redemption Percentage (If Sustainability Performance Target has been satisfied and confirmed by External Verifier)”) plus (2) interest payments due on the note through February 15, 2027 (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%, over (B) the principal amount of the note. In addition, on

or after February 15, 2027, 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 during the twelve-month period beginning on February 15 of the years indicated below, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Year	Redemption Percentage (If Sustainability Performance Target has been satisfied and confirmed by External Verifier)		Redemption Percentage (If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)
2027	101.938	%	102.188	%
2028	101.292	%	101.458	%
2029	100.646	%	100.729	%
2030 and thereafter	100.000	%	100.000	%

Receivables Facility

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.

On July 26, 2021, NRG Receivables LLC entered into the First Amendment to the Receivables Facility with a group of conduit lenders and banks and Royal Bank of Canada, as Administrative Agent to, among other things, (i) increase the existing revolving commitments by $50 million to an aggregate amount of $800 million, (ii) extend the maturity date until July 26, 2022, (iii) make certain adjustments to the pool of receivables through the Receivables Facility and certain related covenants and (iv) provide for revised language relating to interest determination based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events. 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 Receivables Facility as of December 31, 2021 was 0.646%. As of December 31, 2021, there were no outstanding borrowings and there were $400 million in letters of credit issued under the Receivables Facility.

Repurchase Facility

On September 22, 2020, the Company entered into the Repurchase Facility related to the Receivables Facility. Under the Repurchase Facility, the Company can borrow up to $75 million, collateralized by a subordinated note issued by NRG Receivables LLC to NRG Retail LLC in favor of the originating entities representing a portion of the balance of receivables sold to NRG Receivables LLC under the Receivables Facility.

On July 26, 2021, the Company renewed its existing Repurchase Facility to, among other things, (i) extend the maturity date to July 26, 2022 and (ii) provide for revised language relating to interest determination based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events. On February 9, 2022, the Company entered into amendments to its existing Repurchase Facility to, among other things, (i) increase the size of the facility from $75 million to $150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate. The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%. As of December 31, 2021, there were no outstanding borrowings under the Repurchase Facility.

Senior Credit Facility

Revolving Credit Facility Modification

During the third quarter of 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, and (ii) provide for a new tranche of revolving commitments in an aggregate amount of $273 million with a maturity date of July 5, 2023. The maturity date of the new revolving tranche of commitments may, upon request by the Company, and at the option of each applicable lender under the

new tranche be extended to 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 loans made pursuant thereto are identical. The increase in the existing commitments, and the commitments with respect to the new tranche were effective on August 20, 2020 and became available on January 5, 2021 upon the closing of the Direct Energy Acquisition. As of December 31, 2021, total revolving commitments available, subject to usage, under the amended credit agreement was $3.7 billion.

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, 2021, $222 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, 2021, $469 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%.

In connection with the issuance of the P-Caps, on December 11, 2020, NRG entered into an amended and restated facility agreement for the issuance of letters of credit (the “LC Agreement”) with Deutsche Bank Trust Company Americas as collateral agent (the “Collateral Agent”) and administrative agent pursuant to which certain financial institutions (the “LC Issuers”) have agreed to provide letters of credit in an aggregate amount not to exceed $874 million to support the operations of NRG and its subsidiaries and minority investments, including to replace certain letters of credit and other credit support issued for the account of entities acquired pursuant to the Direct Energy Acquisition. In addition, on December 11, 2020, the Trust entered into an amended and restated pledge and control agreement (the “Pledge Agreement”), among NRG, the Trust and the Collateral Agent for the LC Issuers, under which the Trust agreed to grant a pledge over the Eligible Treasury Assets in favor of the Collateral Agent for the benefit of the LC Issuers. Pursuant to the LC Agreement and the Pledge Agreement, the Collateral Agent is entitled to withdraw Eligible Treasury Assets from the Trust’s pledged account, following notice to NRG, in the event NRG has failed to reimburse amounts drawn under any letter of credit issued pursuant to the LC Agreement, and the LC Issuers have the right to instruct the Collateral Agent to enforce the pledge over the Eligible Treasury Assets upon the occurrence of any event of default under the LC Agreement. The LC Agreement and the Pledge Agreement were available on January 5, 2021. As of December 31, 2021, $873 million of letters of credit were issued under the LC Agreement.

Tax Exempt Bonds


	As of December 31,
(In millions, except rates)	2021		2020		Interest Rate %
NRG Indian River Power 2020, tax exempt bonds, due 2040	$	57	$	57	1.250
NRG Indian River Power 2020, tax exempt bonds, due 2045	190		190		1.250
NRG Dunkirk 2020, tax exempt bonds, due 2042	59		59		1.300
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 Dunkirk 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.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-URI http://asc.fasb.org/topic&trid=2208564

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (h)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-URI http://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (g)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1E
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495348-112611

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (i)
-URI http://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

+ Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

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, 2021 and 2020, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2021:


(In millions)	Nuclear Decommission		Other(a)		Total
Balance as of December 31, 2020	$	303	$	457	$	760
Revisions in estimates for current obligations	—		(36)		(36)
Additions	—		5		5
Spending for current obligations	—		(51)		(51)
Accretion	18		24		42
Balance as of December 31, 2021	$	321	$	399	$	720

(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 Postretirement Benefits

12 Months Ended

Dec. 31, 2021

Retirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

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

NRG pension benefits are available to eligible non-union and union employees through various defined benefit pension plans. These benefits are based on pay, service history and age at retirement. Most pension benefits are provided through tax-qualified plans. NRG also provides postretirement health and welfare benefits for certain groups of employees. Cost sharing provisions vary by the terms of any applicable collective bargaining agreements.

NRG maintains three separate qualified pension plans, the NRG Pension Plan for Bargained Employees, the NRG Pension Plan and the Pension Plan for Employees of Direct Energy Marketing Limited ("DEML"). Participation in the NRG Pension Plan for Bargained Employees depends upon whether an employee is covered by a bargaining agreement. The NRG Pension plan was frozen for non-union employees on December 31, 2018. The Pension Plan for Employees of DEML is closed to new participants.

Due to updated assumptions as a result of ARPA, NRG does not expect to contribute to the Company's pension plans in 2022.

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)	2021		2020		2019
Service cost benefits earned	$	9	$	10	$	10
Interest cost on benefit obligation	27		38		46
Expected return on plan assets	(66)		(61)		(59)
Amortization of unrecognized net loss	1		5		3
Settlement/curtailment expense	2		—		—
Net periodic benefit (credit)/cost	$	(27)	$	(8)	$	—


	Year Ended December 31,
	Other Postretirement Benefits
(In millions)	2021		2020		2019
Service cost benefits earned	$	—	$	—	$	1
Interest cost on benefit obligation	2		3		3
Amortization of unrecognized prior service cost	(10)		(14)		(13)
Amortization of unrecognized net loss	1		1		—
Curtailment loss	1		—		—
Net periodic benefit credit	$	(6)	$	(10)	$	(9)

A comparison of the pension benefit obligation, other postretirement benefit obligations and related plan assets for NRG's plans on a combined basis is as follows:


	As of December 31,
	Pension Benefits				Other Postretirement Benefits
(In millions)	2021		2020		2021		2020
Benefit obligation at January 1	$	1,489	$	1,397	$	90	$	93
Acquired benefit obligation from Direct Energy	74		—		19		—
Service cost	9		10		—		—
Interest cost	27		38		2		3

Actuarial (gain)/loss	(55)		126		—		—
Employee and retiree contributions	—		—		3		3
Curtailment loss	—		—		1		—
Benefit payments	(93)		(82)		(10)		(9)
Foreign exchange translation	1		—		—		—
Benefit obligation at December 31	1,452		1,489		105		90
Fair value of plan assets at January 1	1,272		1,150		—		—
Acquired fair value of plan assets from Direct Energy	64		—				—
Actual return on plan assets	85		193		—		—
Employee and retiree contributions	—		—		3		3
Employer contributions	7		11		7		6
Benefit payments	(93)		(82)		(10)		(9)
Foreign exchange translation	1		—		—		—
Fair value of plan assets at December 31	1,336		1,272		—		—
Funded status at December 31 — excess of obligation over assets	$	(116)	$	(217)	$	(105)	$	(90)

During the year ended December 31, 2021, the actuarial gain of $55 million on pension benefits was primarily driven by increasing discount rates and changes in demographic assumptions.

During the year ended December 31, 2020, the actuarial loss of $126 million on pension benefits was driven by decreasing discount rates and changes in demographic assumptions, 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)	2021		2020		2021		2020
Other current liabilities	$	—	$	—	$	7	$	5
Other non-current liabilities	116		217		98		85

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)	2021		2020		2021		2020
Net loss	$	52	$	127	$	5	$	6
Prior service cost/(credit)	2		2		(19)		(29)
Total accumulated OCI	$	54	$	129	$	(14)	$	(23)

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)	2021		2020		2021		2020
Net actuarial gain	$	(72)	$	(6)	$	—	$	—
Amortization of net actuarial loss	(1)		(5)		(1)		(1)


Amortization of prior service cost	—		—		10		14
Effect of settlement	(2)		—		—		—
Total recognized in OCI	$	(75)	$	(11)	$	9	$	13
Net periodic benefit credit	(27)		(8)		(6)		(10)
Net recognized in net periodic pension credit and OCI	$	(102)	$	(19)	$	3	$	3

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


	As of December 31,
	Pension Benefits
(In millions)	2021		2020
Projected benefit obligation	$	1,452	$	1,489
Accumulated benefit obligation	1,423		1,455
Fair value of plan assets	1,336		1,272

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, 2021
(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	$	—	$	221	$	221
Common/collective trust investment — non-U.S. equity	—		69		69
Common/collective trust investment — non-core assets	—		110		110
Common/collective trust investment — fixed income	—		340		340
Short-term investment fund	13		—		13
Subtotal fair value	$	13	$	740	$	753
Measured at net asset value practical expedient:
Common/collective trust investment — non-U.S. equity					78
Common/collective trust investment — fixed income					405
Common/collective trust investment — non-core assets					65
Partnerships/joint ventures					35
Total fair value					$	1,336


	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

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	2021		2020		2021		2020
Discount rate	2.89	%	2.56	%	2.89	%	2.54	%
Interest crediting rate	3.07	%	3.12	%	1.94	%	1.62	%
Rate of compensation increase	3.06	%	3.00	%	—	%	—	%
Health care trend rate	—		—		6.8% grading to 4.4% in 2028		7.2% 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	2021		2020		2019		2021		2020		2019
Discount rate	2.55	%	3.26	%	4.38%/4.20%		2.81%		3.26	%	4.37	%
Interest crediting rate	3.13	%	3.66	%	—		1.62	%	2.28	%	—
Expected return on plan assets	5.62	%	5.93	%	6.35	%	—		—		—
Rate of compensation increase	3.06	%	3.00	%	3.00	%	—		—		—
Health care trend rate	—		—		—		7.0% grading to 4.4% in 2028		7.5% grading to 4.5% in 2028		7.8% 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 and the AON Canada yield curve to select the appropriate discount rate assumption for its retirement plans. 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. Under the AA-AM yield curve, 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. The AON Canada yield curve is based on high quality corporate bonds. Under the AON Canada yield curve, expected plan cash flows were discounted using the the yield curve, and then a single rate is determined which produces an equivalent present value.

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, 2021:


U.S. equity	17	%
Non-U.S. equity	13	%
Non-core assets	15	%
Fixed Income	55	%

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 Index
Non-core assets(a)						Various (per underlying asset class)
Fixed income securities						Barclays Short, Intermediate and Long Credits/Barclays Strips 20+ Index and FTSE Canada Universe Bond 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
2022	$	96	$	7	$	—
2023	94		7		—
2024	91		7		—
2025	87		6		—
2026	86		6		—
2027-2031	396		26		2

STP Defined Benefit Plans

NRG has a 44% undivided ownership interest in STP, as discussed further in Note 28, 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 2019, STPNOC announced that the defined benefit pension plan would be frozen. 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. As of December 31, 2021, the STPNOC defined benefit pension plan was frozen to all employees.

For the years ended December 31, 2021 and December 31, 2020, NRG reimbursed STPNOC $17 million and $8 million, respectively, for its contribution to the plans. In 2022, NRG expects to reimburse STPNOC $13 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)	2021		2020		2021		2020
Funded status — STPNOC benefit plans	$	(50)	$	(99)	$	(18)	$	(20)
Net periodic benefit cost/(credit)	17		7		(4)		(4)
Other changes in plan assets and benefit obligations recognized in other comprehensive income	(51)		22		4		5

Defined Contribution Plans

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

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


	Year Ended December 31,
(In millions)	2021		2020		2019
Company contributions to defined contribution plans	$	25	$	22	$	22

- Definition

The entire disclosure for retirement benefits.

+ References

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+ Details

Capital Structure

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Capital Structure

For the period from December 31, 2018 to December 31, 2021, 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 Shares
	Issued	Treasury	Outstanding
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
Shares issued under ESPP	—	117,392	117,392
Shares issued under LTIPs	489,326	—	489,326
Share repurchases	—	(1,084,752)	(1,084,752)
Balance as of December 31, 2021	423,547,174	(179,793,275)	243,753,899
Shares issued under LTIPs	288,491	—	288,491
Share repurchases	—	(1,889,151)	(1,889,151)
Balance as of February 24, 2022	423,835,665	(181,682,426)	242,153,239

Common Stock

As of December 31, 2021, NRG had 14,372,743 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 $0.325, $0.30 and $0.03 quarterly dividend per common share, or $1.30, $1.20 and $0.12 per share on an annualized basis for 2021, 2020 and 2019 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 and 2022, NRG increased the annual dividend to $1.30 and $1.40 per share, representing an 8% increase each year. 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, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, or $1.40 per share on an annualized basis, payable on February 15, 2022, to stockholders of record as of February 1, 2022.

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. As of December 31, 2021, there remained 2,636,199 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 and were made under the long-term capital allocation policy discussed above. On December 6, 2021 the Company announced that the Board of Directors has authorized $1 billion for share repurchases, as part of NRG’s Capital Allocation Program. The program began in 2021 and will continue throughout 2022.

The following table summarizes the shares repurchases made during the years ended December 31, 2019, 2020 and 2021 as well as through February 24, 2022:


	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)


2019 repurchases:
Repurchases under February 28, 2019 Accelerated Share Repurchase Agreement	9,438,671			400
Other repurchases(a)	26,863,211			1,008
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	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(b)	711,248			27
Total Share Repurchases during 2020	6,774,031	$	33.05	$	224
2021 repurchases:
Repurchases(a)	1,084,752			44
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	249,013			9
Total Share Repurchases during 2021	1,333,765	$	40.22	$	53
2022 repurchases:
Repurchases made subsequent to December 31, 2021	1,889,151			76
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	130,674			6
Total share repurchases January 1, 2021 through February 24, 2022	2,019,825	$	40.26	$	82

(a)Includes $5 million and $4 million accrued as of December 31, 2021 and December 31,2019, respectively

(b)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 $43.08, $37.50, $38.23 and $38.78 in 2022, 2021, 2020 and 2019, respectively. See Note 21, Stock-Based Compensation, for further discussion of the equity awards

- Definition

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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+ Details

Investments Accounted for by the Equity Method and Variable Interest Entities

12 Months Ended

Dec. 31, 2021

Equity Method Investments and Joint Ventures [Abstract]

Investments Accounted for by the Equity Method and Variable Interest Entities

Entities that are not Consolidated

NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by a number of elements including impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates.

The following table summarizes NRG's equity method investments as of December 31, 2021:


(In millions, except percentages)
Name:	Economic Interest		Investment Balance(a)
Gladstone	37.5	%	$	127
Ivanpah Master Holdings, LLC	54.5	%	4
Watson Cogeneration Company	49.0	%	14
Midway-Sunset Cogeneration Company	50.0	%	12
Total equity investments in affiliates			$	157
Petra Nova Parish Holdings, LLC(b)	50.0	%	$	(16)

(a)As of December 31, 2021, the carrying value of NRG's equity method investment was $116 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 the treatment of certain deferred tax assets

(b)The Company continues to account for Petra Nova under the equity method due to the fact that NRG still has a financial guaranty. As a result, the Company continues to record losses for a negative equity method investment. As of December 31, 2021, NRG recorded $16 million to other non-current liabilities. Refer to Note 11, Asset Impairments, for discussion of NRG's investment in Petra Nova Parish Holdings, LLC


	As of December 31,
(In millions)	2021		2020
Undistributed earnings from equity investments	$	33	$	30

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.

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 $127 million as of December 31, 2021.

Entities that are Consolidated

The Company has a controlling financial interest that has been identified as a VIE under ASC 810 in NRG Receivables LLC, which has entered into financing transactions related to the Receivables Facility as further described in Note 13, Long-term Debt and Finance Leases.

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


(In millions)	December 31, 2021		December 31, 2020
Accounts receivable	$	939	$	647
Other current assets	—		2


Total assets	939		649
Current liabilities	78		78




Net assets	$	861	$	571

Income Per Share

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Income 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 relative performance stock units, non-vested restricted stock units, market stock units and non-qualified stock options 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. As of December 31, 2021, 2020 and 2019, the Convertible Senior Notes were convertible, under certain circumstances, into the Company’s common stock, cash or combination thereof (at NRG's option). There was no dilutive effect for the Convertible Senior Notes due to the Company’s expectation, as of such dates, to settle the liability in cash. On February 22, 2022, the Company irrevocably elected to eliminate the right to settle conversions only in shares of the Company's common stock, such that any conversion after such date will be settled in cash or a combination of cash and the Company's common stock.

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


	Year Ended December 31,
(In millions, except per share amounts)	2021		2020		2019
Basic income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. common stockholders	$	2,187	$	510	$	4,438



Weighted average number of common shares outstanding-basic	245		245		262
Income per weighted average common share — basic	$	8.93	$	2.08	$	16.94
Diluted income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. common stockholders	$	2,187	$	510	$	4,438
Weighted average number of common shares outstanding-basic	245		245		262
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—		1		2
Weighted average number of common shares outstanding-diluted	245		246		264
Income per weighted average common share — diluted	$	8.93	$	2.07	$	16.81

As of December 31, 2021, 2020 and 2019 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

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Segment Reporting

The Company’s segment structure reflects how management makes financial decisions and allocates resources. The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus.

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.

The acquired operations of Direct Energy are integrated into the existing NRG segment structure. Domestic customer and market operations are combined into the corresponding geographical segments of Texas, East and West/Services/Other. The West/Services/Other segment includes activity related to the Canadian operations as well as the services businesses.

In February 2019, the Company completed the sale and deconsolidation of the South Central Portfolio and Carlsbad. 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, 2021, 2020 and 2019.

Intersegment sales are accounted for at market.


	For the Year Ended December 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate(a)		Eliminations		Total
Operating revenues(a)	$	10,293	$	13,033	$	3,653	$	—	$	10	$	26,989
Operating expenses	8,692		10,257		3,466		141		10		22,566
Depreciation and amortization	331		338		88		28		—		785
Impairment losses	—		535		9		—		—		544
Total operating cost and expenses	9,023		11,130		3,563		169		10		23,895

Gain on sale of assets	19		—		17		211		—		247
Operating income	1,289		1,903		107		42		—		3,341
Equity in (losses)/earnings of unconsolidated affiliates	(3)		—		20		—		—		17

Other income, net	8		7		3		59		(14)		63
Loss on debt extinguishment	—		—		—		(77)		—		(77)
Interest expense	(1)		(1)		(28)		(469)		14		(485)
Income/(loss) from continuing operations before income taxes	1,293		1,909		102		(445)		—		2,859
Income tax expense	—		—		19		653		—		672




Net income/(loss) attributable to NRG Energy, Inc.	$	1,293	$	1,909	$	83	$	(1,098)	$	—	$	2,187

Balance sheet
Equity investments in affiliates	$	—	$	—	$	157	$	—	$	—	$	157
Capital expenditures	153		50		21		45		—		269
Goodwill	751		853		191		—		—		1,795
Total assets	$	12,265	$	13,673	$	4,816	$	19,081	$	(26,653)	$	23,182


(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues			$	5					$	(18)					$	3					$	—					$	—					$	(10)


	For the Year Ended December 31, 2020
(In millions)	Texas		East		West/Services/Other		Corporate(a)		Eliminations		Total
Operating revenues(a)	$	6,309	$	2,258	$	530	$	—	$	(4)	$	9,093
Operating expenses	5,249		1,758		421		57		(4)		7,481
Depreciation and amortization	227		138		36		34		—		435
Impairment losses	14		—		61		—		—		75
Total operating cost and expenses	5,490		1,896		518		91		(4)		7,991

(Loss)/gain on sale of assets	—		—		(2)		5		—		3
Operating income/(loss)	819		362		10		(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	800		351		39		(429)		—		761
Income tax (benefit)/expense	—		(1)		2		250		—		251




Net income attributable to NRG Energy, Inc.	$	800	$	352	$	37	$	(679)	$	—	$	510

Balance sheet
Equity investments in affiliates	$	(13)	$	—	$	359	$	—	$	—	$	346
Capital expenditures	130		45		30		25		—		230
Goodwill(b)	324		240		15		—		—		579
Total assets	$	7,641	$	1,790	$	1,679	$	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/Services/Other		Corporate(a)		Eliminations		Total
Operating revenues(a)	$	7,069	$	2,262	$	497	$	—	$	(7)	$	9,821
Operating expenses	5,821		1,843		453		50		(7)		8,160
Depreciation and amortization	188		117		37		31		—		373
Impairment losses	1		—		4		—		—		5
Total operating cost and expenses	6,010		1,960		494		81		(7)		8,538

Gain on sale of assets	—		1		—		6		—		7
Operating income/(loss)	1,059		303		3		(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		291		6		(483)		—		786
Income tax expense/(benefit)	—		2		1		(3,337)		—		(3,334)
Net income from continuing operations	972		289		5		2,854		—		4,120
Gain from discontinued operations, net of income tax	—		—		—		321		—		321
Net Income	972		289		5		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	$	289	$	2	$	3,175	$	—	$	4,438


(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues			$	1					$	8					$	(2)					$	—					$	—					$	7

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

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)	2021			2020			2019
Current

State	$	48		$	22		$	2
Foreign	3			4			4
Total — current	51			26			6
Deferred
U.S. Federal	569			168			(3,000)
State	36			60			(340)
Foreign	16			(3)			—
Total — deferred	621			225			(3,340)
Total income tax expense/(benefit)	$	672		$	251		$	(3,334)
Effective income tax rate	23.5		%	33.0		%	(424.2)		%

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)	2021		2020		2019
U.S.	$	2,759	$	749	$	771
Foreign	100		12		15
Total	$	2,859	$	761	$	786

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)	2021			2020			2019
Income from continuing operations before income taxes	$	2,859		$	761		$	786
Tax at federal statutory tax rate	600			160			165
Foreign rate differential	(3)			—			—
State taxes	111			18			13

Permanent differences	8			8			(9)
Changes in valuation allowance	(29)			24			(3,492)


Deferred impact of state tax rate changes	(10)			2			12

Recognition of uncertain tax benefits	(10)			3			(10)
Return to provision adjustments	5			36			—




Other	—			—			(13)
Income tax expense/(benefit)	$	672		$	251		$	(3,334)
Effective income tax rate	23.5		%	33.0		%	(424.2)		%

For the year ended December 31, 2021, NRG's effective income tax rate was higher than the federal statutory tax rate of 21% primarily due to state tax expense partially offset by tax benefits from the revaluation of state deferred tax assets, valuation allowance, and settlements of uncertain tax positions.

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.

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)	2021		2020
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	$	114	$	79
Difference between book and tax basis of property	436		357


Pension and other postretirement benefits	65		86
Equity compensation	7		10
Bad debt reserve	168		16
Derivatives, net	—		11
U.S. Federal net operating loss carryforwards	1,773		2,117
Foreign net operating loss carryforwards	112		102
State net operating loss carryforwards	328		351

Federal and state tax credit carryforwards	384		384
Federal benefit on state uncertain tax positions	3		4

Interest disallowance carryforward per §163(j) of the Tax Act	6		4
Inventory obsolescence	9		6
Other	15		10

Total deferred tax assets	3,420		3,537
Deferred tax liabilities:
Emissions allowances	20		21


Derivatives	591		—
Goodwill	40		29
Intangibles amortization (excluding goodwill)	363		2
Equity method investments	62		156

Convertible Debt	14		16


Total deferred tax liabilities	1,090		224
Total deferred tax assets less deferred tax liabilities	2,330		3,313
Valuation allowance	(248)		(266)

Total net deferred tax assets, net of valuation allowance	$	2,082	$	3,047

The following table summarizes NRG's net deferred tax position as presented in the consolidated balance sheets:


	As of December 31,
(In millions)	2021		2020
Deferred tax asset	$	2,155	$	3,066

Deferred tax liability	(73)		(19)
Net deferred tax asset	$	2,082	$	3,047

The primary drivers for the decrease in the net deferred tax asset from $3.0 billion as of December 31, 2020 to $2.1 billion as of December 31, 2021 are an increase in mark-to-market book gains and step-up in basis of book intangibles associated with the acquisition of Direct Energy.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of December 31, 2021 and 2020, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.3 billion and $3.3 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, 2021 as discussed below.

NOL carryforwards — As of December 31, 2021, the Company had tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.8 billion and $328 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 $112 million with no expiration date.

Valuation allowance — As of December 31, 2021, the Company's tax-effected valuation allowance was $248 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, 2021, NRG recorded a current net federal receivable of $16 million, comprised of refunds due from the IRS, a current net state tax payable of $13 million that is primarily comprised of Texas margin tax, and a current net foreign receivable of $11 million due to filings of Canadian amended returns as well as prepayments of estimated taxes.

Uncertain tax benefits

NRG has identified uncertain tax benefits with after-tax value of $13 million and $15 million as of December 31, 2021 and 2020, for which NRG has recorded a non-current tax liability of $14 million and $18 million, respectively. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. The Company recognized an immaterial amount of interest expense for the year ended December 31, 2021, and $1 million for the years ended 2020 and 2019. As of December 31, 2021 and 2020, NRG had cumulative interest and penalties related to these uncertain tax benefits of $1 million and $3 million, respectively.

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

The Company is no longer subject to U.S. federal income tax examinations for years prior to 2018. With few exceptions, state and Canadian income tax examinations are no longer open for years before 2013.

The following table summarizes uncertain tax benefits activity:


	As of December 31,
(In millions)	2021		2020
Balance as of January 1	$	15	$	15
Increase due to current year positions	4		3
Increase due to acquired balance from Direct Energy	9		—

Settlements, payments and statute closure	(15)		(3)
Uncertain tax benefits as of December 31	$	13	$	15

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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+ Details

Stock-Based Compensation

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement, Noncash Expense [Abstract]

Stock-Based Compensation

NRG Energy, Inc. Long-Term Incentive Plan

On April 27, 2017, the NRG LTIP was amended to increase the number of shares available for issuance by 3,000,000. As of December 31, 2021 and 2020, a total of 25,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP. There were 8,871,874 and 9,385,730 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 2021 and 2020, 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, 2021 and 2020, there were 20,131 and 78,903 shares of common stock remaining available for grants under the NRG GenOn LTIP, respectively.

Restricted Stock Units

As of December 31, 2021, RSUs granted under the Company's LTIPs typically have three-year graded vesting schedules beginning on the grant date. Fair value of the RSUs granted during 2021 and 2020 is derived from the closing price of NRG common stock on the grant date. 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, 2020	519,514	$	35.87
Granted	479,415	39.00
Forfeited	(49,816)	37.41
Vested	(279,161)	34.18

Non-vested at December 31, 2021	669,952	38.69

The total fair value of RSUs vested during the years ended December 31, 2021, 2020 and 2019 was $12 million, $17 million and $36 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2021, 2020 and 2019 was $39.00, $38.05 and $37.37, 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, 2020	342,706	$	25.37
Granted	64,512	32.27

Converted to Common Stock	(23,090)	30.92

Outstanding at December 31, 2021	384,128	26.11

The aggregate intrinsic values for DSUs outstanding as of December 31, 2021, 2020 and 2019 were approximately $17 million, $13 million and $13 million, respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2021, 2020 and 2019 were $1 million, $2 million and $2 million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2021, 2020 and 2019 was $32.27, $35.59 and $34.84, 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, 2021, non-vested PSUs consist 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(a). Each RPSU represents the potential to receive NRG common stock after the completion of the performance period, typically three years of service from the date of grant. The number of shares of NRG common stock to be paid (if any) as of the vesting date for each RPSU will depend on the Company’s percentile rank within the Peer Group. The number of shares of common stock to be paid as of the vesting date for each RPSU is linearly interpolated for TSR performance between the following points: (i) 0% if ranked below the 25th percentile; (ii) 25% if ranked at the 25th percentile; (iii) 100% if ranked at the 55th percentile (or the 65th percentile if the Company's absolute TSR is less than negative 15%); and (iv) 200% if ranked at the 75th percentile or above. The value of the common stock on the date of grant is based on the closing price of NRG common stock on the date of grant.

(a) For RPSU's granted in 2022 and forward the peer group will consist of the companies that comprise the Standard & Poor’s 500 Index on the first day of the performance period.

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, 2020	793,561	$	41.69
Granted	426,768	46.78
Forfeited	(93,031)	47.21
Vested	(396,793)	35.32
Non-vested at December 31, 2021	730,505	47.40

The weighted average grant date fair value of PSUs granted during the years ended December 31, 2021, 2020 and 2019, was $46.78, $23.75 and $22.50, 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:


	2021(a)		2020		2019
	RPSUs		RPSUs		RPSUs
Expected volatility	34.05	%	30.15	%	40.72	%
Expected term (in years)	3		3		3
Risk free rate	0.17	%	1.58	%	2.45	%

(a) Assumptions pertain to the main award granted in January 2021. Additional 60,815 RPSUs were granted in September 2021 with a risk free rate of 0.42% and expected volatility of 37.38%

For the years ended December 31, 2021 and 2020, 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, 2021, 2020 and 2019. No NQSOs were granted in 2021, 2020 or 2019. NRG recognized compensation costs for NQSOs over the requisite service period for the entire award. No compensation expense was recognized during 2021, 2020 or 2019 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, 2020	77,047	$	25.13	0.5	$	1
Expired	(4,800)	29.08
Exercised	(54,377)	26.44
Outstanding at December 31, 2021	17,870	20.07		0.2	—
Exercisable at December 31, 2021	17,870	20.07		0.2	—

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)	2021		2020		2019

Total intrinsic value of options exercised	$	1	$	1	$	2
Cash received from options exercised	1		1		3

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, 2021, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $9 million, $27 million, and $36 million for the years ended December 31, 2021, 2020, and 2019, 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	2021		2020		2019		2021		2021

RSUs	$	9	$	9	$	9	$	16	1.80
DSUs	2		2		2		—		0.00

RPSUs	9		10		10		15		1.19
PRSUs(a)	7		6		11		10		1.52
Total	$	27	$	27	$	32	$	41
Tax detriment/(benefit) recognized	$	2	$	(9)	$	(12)

(a)Phantom Restricted Stock Units, PRSUs, are liability-classified time-based awards that typically vest ratably over a three-year period. The amount to be paid upon vesting is based on NRG's closing stock price for the period

Related Party Transactions

12 Months Ended

Dec. 31, 2021

Related Party Transactions

NRG provides services to some of its related parties, who are accounted for as 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)	2021		2020		2019
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	4	$	4	$	4
Ivanpah(a)	39		43		35
Midway-Sunset	6		5		5
Total	$	49	$	52	$	44

(a)Includes fees under project management agreements with each project company

Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Certain Fuel and Transportation Commitments

NRG has entered into long-term contractual arrangements to procure certain fuel and transportation services for the Company's generation assets.

As of December 31, 2021, the Company's minimum commitments under such outstanding agreements are estimated as follows:


Period	(In millions)
2022	$	122
2023	54
2024	63
2025	62
2026	51
Thereafter	26
Total(a)	$	378

(a)Actual fuel and transportation purchases are significantly higher than these estimated minimum unconditional long-term firm commitments with remaining term in excess of one year

For the years ended December 31, 2021, 2020 and 2019, the costs of certain fuel and transportation were $0.6 billion, $0.5 billion and $0.6 billion, respectively.

Purchased Energy Commitments

NRG has long-term contractual commitments related to electricity and natural gas products, including power purchases, gas transportation and storage of various quantities and durations, and 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, 2021. Minimum purchase commitment obligations are as follows as of December 31, 2021:


Period	(In millions)
2022	$	1,566
2023	1,036
2024	617
2025	382
2026	289
Thereafter	1,071
Total(a)	$	4,961

(a)Actual energy purchases are significantly higher than these estimated minimum unconditional long-term firm commitments with remaining term in excess of one year

For the years ended December 31, 2021, 2020 and 2019, the costs of purchased energy were $12.8 billion, $1.8 billion and $2.6 billion, respectively.

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, 2021, hedges under the first lien were out-of-the-money for NRG on a counterparty aggregate basis.

Nuclear Insurance

STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Act. 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 months after the policy term, whereas NEIL's Board of Directors can make such an adjustment up to 6 years after the policy expires. All insurance coverage is subject to various sub limits and significant deductibles.

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 24, Regulatory Matters, and Note 25, 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.

Environmental Lawsuits

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.

Consumer Lawsuits

Similar to other energy service companies (“ESCOs”) operating in the industry, from time-to-time, the Company and/or its subsidiaries may be subject to consumer lawsuits in various jurisdictions where they sell natural gas and electricity.

Variable Price Cases — In the cases set forth below, referred to as the Variable Price Cases, such actions involve consumers alleging that one of the Company’s ESCOs promised that consumers would pay the same or less than they would have paid if they stayed with their default utility or previous energy supplier. The underlying claims of each case are similar and the Company continues to deny the allegations and is vigorously defending these matters. These matters were known and accrued for at the time of each acquisition.

XOOM Energy

XOOM Energy is a defendant in a putative class action lawsuit pending in New York. This case is in the discovery phase.

Direct Energy

There are three putative class actions pending against Direct Energy: (1) Linda Stanley v. Direct Energy (S.D.N.Y Apr. 2019) - The parties mediated in June and agreed on a settlement. On November 16, 2021, the Court granted preliminary approval of the settlement. The final approval hearing will be held on April 5, 2022. It may take several months to determine the final payout amount; (2) Martin Forte v. Direct Energy (N.D.N.Y. Mar. 2017) - The Court recently granted Direct Energy’s Motion for Summary Judgment effectively ending the matter at the district court level. It is likely that the plaintiff will appeal;

however, it is unlikely plaintiff will prevail; (3) Richard Schafer v. Direct Energy (W.D.N.Y. Dec. 2019; on appeal 2nd Cir. N.Y.) - The Court granted limited discovery that will end April 29, 2022. Summary judgement briefing is due on May 20, 2022.

Telephone Consumer Protection Act ("TCPA") Cases — In the cases set forth below, referred to as the TCPA Cases, such actions involve consumers alleging violations of the Telephone Consumer Protection Act of 1991, as amended, by receiving calls, texts or voicemails without consent in violation of the federal Telemarketing Sales Rule, and/or state counterpart legislation. The underlying claims of each case are similar. The Company denies the allegations asserted by plaintiffs and intends to vigorously defend these matters. These matters were known and accrued for at the time of the acquisition.

There are two putative class actions pending against Direct Energy: (1) Brittany Burk v. Direct Energy (S.D. Tex. Feb. 2019) - The Court denied Plaintiff's Motion for Class Certification and Motion for Substitution of a New Plaintiff on September 20, 2021. The parties reached a settlement of the plaintiff's individual claims and the Court has conditionally dismissed the matter; and (2) Matthew Dickson v. Direct Energy (N.D. Ohio Jan. 2018) - Direct Energy has filed a Third-Party Petition against its vendor, Total Marketing Concepts, LLC, who placed voicemails without consent from Direct Energy and in violation of the parties’ agreement. The case was stayed pending the outcome of an appeal to the Sixth Circuit based on the unconstitutionality of the TCPA during the period from 2015-2020. The Sixth Circuit found the TCPA was in effect during that period and remanded the case back to the trial court. Direct Energy refiled its motions along with supplements.

Winter Storm Uri Lawsuits

The Company has been named in certain property damage and wrongful death claims that have been filed in connection with Winter Storm Uri. At this time, the Company is unable to determine the extent or impact of these various litigation matters due to their preliminary nature. The Company intends to vigorously defend these matters.

Indemnifications and Other Contractual Arrangements

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 claimed 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. The Company anticipates a trial, in state court, to begin in 2023. 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.

Regulatory Matters	12 Months Ended
Regulatory Matters	Dec. 31, 2021
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 San Diego Gas & Electric 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. On September 16, 2021, FERC Office of Enforcement Staff informed NRG that the investigation is closed with no further action.

Environmental Matters	12 Months Ended
Environmental Matters	Dec. 31, 2021
Environmental Remediation Obligations [Abstract]
Environmental Matters	Environmental Matters NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. The electric generation industry has been facing increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose additional restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. The Company has elected to use a $1 million disclosure threshold, as permitted, for environmental proceedings to which the government is a party. Air On July 8, 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 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). On October 29, 2021, the U.S. Supreme Court agreed to review the D.C. Circuit's decision, which should provide some clarity regarding the scope of the EPA's authority to regulate CO2 under the Clean Air Act. The Company expects the EPA to promulgate a new rule to regulate GHG emissions from power plants after a decision from the U.S. Supreme Court. Water Effluent Limitations Guidelines — In November 2015, the EPA revised the ELG 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. On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule. While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation. The EPA anticipates releasing a proposed rule in fall 2022. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants in Texas. 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.

Cash Flow Information

12 Months Ended

Dec. 31, 2021

Supplemental Cash Flow Information [Abstract]

Cash Flow Information

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


	Year Ended December 31,
(In millions)	2021		2020		2019
Interest paid, net of amount capitalized	$	433	$	340	$	372
Income taxes paid, net of refunds	32		24		8
Non-cash investing activities:
(Decreases)/additions to fixed assets for accrued capital expenditures	(16)		(6)		1

Guarantees

12 Months Ended

Dec. 31, 2021

Guarantees [Abstract]

Guarantees

NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is obligated with respect to customer deposits associated with the Company's retail operations. In some cases, NRG's maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.

The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity:


	By Remaining Maturity at December 31,
(In millions)	2021
Guarantees	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2020 Total
Letters of credit and surety bonds	$	4,064	$	31	$	—	$	—	$	4,095	$	1,153
Asset sales guarantee obligations	269		25		24		96		414		506
Other guarantees	—		—		—		93		93		87
Total guarantees	$	4,333	$	56	$	24	$	189	$	4,602	$	1,746

Letters of credit and surety bonds — As of December 31, 2021, NRG and its consolidated subsidiaries were contingently obligated for a total of $4.1 billion under letters of credit and surety bonds. The significant increase in 2021 is primarily due to the acquisition of Direct Energy. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements and obligations associated with future closure and maintenance of ash sites, as well as for financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms.

The material indemnities, within the scope of ASC 460, are as follows:

Asset sales — The purchase and sale agreements which govern NRG's asset or share investments and divestitures customarily contain guarantees and indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations included in the table above, 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 $158 million as of December 31, 2021 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

12 Months Ended

Dec. 31, 2021

Jointly Owned Plants Disclosure [Abstract]

Jointly Owned Plants

Certain NRG subsidiaries own undivided interests in jointly-owned plants, as described below. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries' share of operating costs and direct expenses and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company's consolidated financial statements.

The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities:


(In millions unless otherwise stated)
As of December 31, 2021	Ownership Interest		Property, Plant & Equipment		Accumulated Depreciation		Construction in Progress
South Texas Project Units 1 and 2, Bay City, TX	44.00	%	$	421	$	(208)	$	4
Cedar Bayou Unit 4, Baytown, TX	50.00	%	220		(109)		12

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

12 Months Ended

Dec. 31, 2021

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, 2021, 2020 and 2019


(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, 2021	$	67	$	698	$	112	$	(194)	(a)	$	683
Year Ended December 31, 2020	43		108		—		(84)		(a)	67
Year Ended December 31, 2019	32		95		—		(84)		(a)	43
Income tax valuation allowance, deducted from deferred tax assets
Year Ended December 31, 2021	$	266	$	(29)	$	11	$	—		$	248
Year Ended December 31, 2020	242		24		—		—			266
Year Ended December 31, 2019	3,794		(3,543)		(9)		—			242

(a) Represents principally net amounts charged as uncollectible

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Basis of Presentation

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 include highly liquid investments with an original maturity of three months or less at the time of purchase.

Funds Deposited by Counterparties

Winter Storm Uri Uplift Securitization Proceeds

Credit Losses

Restricted Cash


	Year Ended December 31,
(In millions)	2021		2020		2019
Cash and cash equivalents	$	250	$	3,905	$	345
Funds deposited by counterparties	845		19		32
Restricted cash	15		6		8
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$	1,110	$	3,930	$	385

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use.

Inventory

Property, Plant and Equipment

Asset Impairments

Development Costs and Capitalized Interest

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

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

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

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

Contract and Emission Credit Amortization

Retail Revenue

Energy Revenue

Ancillary revenues, included in Other revenue, are recognized over time as the obligation is fulfilled, using the output method for measuring progress of satisfaction of performance obligations.

Capacity Revenue

Lease Revenue and Lessor Accounting

Lease 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

Gross Receipts and Sales Taxes

Cost of Operations, Cost of Fuel, Purchased Energy and Other Cost of Sales

Cost of Operations

Cost of Fuel, Purchased Energy and Other Cost of Sales

Derivative Instruments

As of December 31, 2021 and 2020 the Company did not have derivative instruments that were designated as cash flow or fair value or hedge.

Mark-to-Market for Economic Hedging Activities

Cost of Operations, Maintenance and Other Costs of Operations

Operations and Maintenance and Other Cost of Operations

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

Fair Value of Financial Instruments

Asset Retirement Obligations

Pensions and Other Postretirement Benefits

The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820.

Stock-Based Compensation

Investments Accounted for by the Equity Method

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

Sale-Leaseback Arrangements

Lease 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

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.

Business Combinations

Use of Estimates

Reclassifications

Certain prior period 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 2021

Recent Accounting Developments - Guidance Not Yet Adopted

Revenue Recognition

Contract and Emission Credit Amortization

Retail Revenue

Energy Revenue

Ancillary revenues, included in Other revenue, are recognized over time as the obligation is fulfilled, using the output method for measuring progress of satisfaction of performance obligations.

Capacity Revenue

Nuclear Decommissioning Policy

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Accounts Receivable, Allowance for Credit Loss

The following table represents the activity in the allowance for credit losses for the year ended December 31, 2021:


	Year Ended December 31,
(In millions)	2021		2020
Beginning balance	$	67	$	43
Acquired balance from Direct Energy	112		—
Provision for credit losses(a)	698		108
Write-offs	(224)		(101)
Recoveries collected	30		17
Ending balance(a)	$	683	$	67

(a)Includes bilateral finance hedging risk of $403 million accounted for under ASC 815

Reconciliation of cash, cash equivalents, and restricted cash and cash equivalents


	Year Ended December 31,
(In millions)	2021		2020		2019
Cash and cash equivalents	$	250	$	3,905	$	345
Funds deposited by counterparties	845		19		32
Restricted cash	15		6		8
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$	1,110	$	3,930	$	385

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


	Year Ended December 31,
(In millions)	2021		2020		2019
Interest paid, net of amount capitalized	$	433	$	340	$	372
Income taxes paid, net of refunds	32		24		8
Non-cash investing activities:
(Decreases)/additions to fixed assets for accrued capital expenditures	(16)		(6)		1

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 and 2019.


	(In millions)







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	$	—

Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2021

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, 2021, 2020 and 2019:


	For the Year Ended December 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue
Home(a)	$	5,665	$	1,959	$	2,053	$	(1)	$	9,676
Business	2,745		9,903		1,237		—		13,885
Total retail revenue	8,410		11,862		3,290		(1)		23,561
Energy revenue(c)	329		508		371		7		1,215
Capacity revenue(c)	—		718		57		—		775
Mark-to-market for economic hedging activities(d)	(3)		(88)		(86)		13		(164)
Contract amortization	—		(26)		(4)		—		(30)
Other revenue(b)(c)	1,557		59		25		(9)		1,632
Total operating revenue	10,293		13,033		3,653		10		26,989
Less: Lease revenue	—		1		7		—		8
Less: Realized and unrealized ASC 815 revenue	130		184		(96)		16		234
Less: Contract amortization	—		(26)		(4)		—		(30)
Total revenue from contracts with customers	$	10,163	$	12,874	$	3,746	$	(6)	$	26,777
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.3 billion driven by high pricing during Winter Storm Uri
(c) 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/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	131	$	2	$	3	$	136
Capacity revenue	—		149		—		—		149
Other revenue	133		(8)		(12)		—		113
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	For the Year Ended December 31, 2020
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue
Home(a)	$	5,027	$	1,210	$	96	$	(2)	$	6,331
Business	1,034		95		—		—		1,129
Total retail revenue	6,061		1,305		96		(2)		7,460
Energy revenue(b)	24		183		333		(1)		539
Capacity revenue(b)	—		620		61		(1)		680
Mark-to-market for economic hedging activities(c)	2		88		(3)		8		95

Other revenue(b)	222		62		43		(8)		319
Total operating revenue	6,309		2,258		530		(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	$	1,943	$	475	$	(7)	$	8,690
(a) Home includes Services
(b) 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/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	67	$	43	$	(5)	$	105
Capacity revenue	—		156		—		—		156
Other revenue	28		3		(2)		—		29
(c) 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/Services/Other		Corporate/Eliminations		Total
Retail revenue
Home(a)	$	5,027	$	1,173	$	57	$	(3)	$	6,254
Business	1,205		74		—		—		1,279
Total retail revenue	6,232		1,247		57		(3)		7,533
Energy revenue(b)	529		322		318		—		1,169
Capacity revenue(b)	—		664		36		—		700
Mark-to-market for economic hedging activities(c)	47		(29)		16		(1)		33

Other revenue(b)	261		58		70		(3)		386
Total operating revenue	7,069		2,262		497		(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	$	2,078	$	411	$	(5)	$	7,991
(a) Home includes Services
(b) 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/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	1,459	$	98	$	39	$	(1)	$	1,595
Capacity revenue	—		109		—		—		109
Other revenue	56		5		12		—		73
(c) 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, 2021 and 2020:


(In millions)	December 31, 2021		December 31, 2020
Deferred customer acquisition costs	$	133	$	113

Accounts receivable, net - Contracts with customers	3,057		866
Accounts receivable, net - Derivative instruments	182		33
Accounts receivable, net - Affiliate	6		5
Total accounts receivable, net	$	3,245	$	904

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,574	$	393

Deferred revenues (a)	$	227	$	60

(a) Deferred revenues from contracts with customers for the years ended December 31, 2021 and 2020 were approximately $224 million and $31 million, respectively

Acquisitions, Discontinued Operations and Dispositions (Tables)

12 Months Ended

Dec. 31, 2021

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Collective Collateral Facilities


	(In millions)
Available on Acquisition Closing Date
Revolving Credit Facility commitment increase	$	802
Revolving Credit Facility new tranche	273
Facility agreement in connection with the sale of pre-capitalized trust securities	874
Available as of December 31, 2020
Credit default swap facility	150
Revolving accounts receivable financing facility	750
Repurchase facility	75
Bilateral letter of credit facilities	475
Total Increases to Liquidity and Collateral Facilities	$	3,399

Schedule of Purchase Price Allocation

The purchase price is allocated as follows:


	(In millions)
Current Assets
Cash and cash equivalents	$	152
Funds deposited by counterparties	21
Restricted cash	9
Accounts receivable, net	1,802
Inventory	106
Derivative instruments	1,014
Cash collateral paid in support of energy risk management activities	233
Prepayments and other current assets	173
Total current assets	3,510
Property, plant and equipment, net	151
Other Assets
Goodwill(a)	1,250
Intangible assets, net:
Customer relationships(b)	1,277
Customer and supply contracts(b)	610
Trade names(b)	310
Renewable energy credits	124
Total intangible assets, net	2,321
Derivative instruments	531
Other non-current assets	31
Total other assets	4,133
Total Assets	$	7,794


	(In millions)
Current Liabilities
Accounts payable	$	1,116
Derivative instruments	1,266
Cash collateral received in support of energy risk management activities	21
Accrued expenses and other current liabilities	670
Total current liabilities	3,073
Other Liabilities
Derivative instruments	562
Deferred income taxes	320
Other non-current liabilities	115
Total other liabilities	997
Total Liabilities	$	4,070

Direct Energy Purchase Price	$	3,724

(b)The weighted average amortization period for total amortizable intangible assets is 12 years

The following measurement period adjustments were recognized during the quarter ended December 31, 2021:


	(In millions)
Assets
Prepayments and other current assets	$	(10)

Goodwill	(7)

Total decrease in assets	$	(17)
Liabilities
Accounts payable	$	(4)
Accrued expenses and other current liabilities	(20)
Deferred income taxes	(18)

Total decrease in liabilities	$	(42)
Net measurement period adjustments	$	25

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

Fair Values of Derivative Assets and Liabilities as of Acquisition Closing Date

The fair values of derivatives assets and liabilities as of the Acquisition Closing Date were as follows:


	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Derivatives assets	$	1,545	$	155	$	1,272	$	118
Derivatives liabilities	1,828		207		1,489		132


	As of December 31, 2021
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	32	$	15	$	17	$	—

Nuclear trust fund investments:
Cash and cash equivalents	33		33		—		—
U.S. government and federal agency obligations	112		111		1		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	44		—		44		—
Corporate debt securities	122		—		122		—
Equity securities	494		494		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Foreign exchange contracts	1		—		1		—
Commodity contracts	7,139		981		5,701		457


Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	99
Equity securities (classified within other non-current assets)	7
Total assets	$	8,188	$	1,635	$	5,990	$	457
Derivative liabilities:
Foreign exchange contracts	$	1	$	—	$	1	$	—
Commodity contracts	$	4,798	$	626	$	4,008	$	164

Total liabilities	$	4,799	$	626	$	4,009	$	164


	As of December 31, 2020
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current or 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 (classified within other non-current assets):
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 (classified within other non-current assets)	8
Total assets	$	1,745	$	597	$	914	$	139
Derivative liabilities:
Commodity contracts	$	884	$	86	$	643	$	155

Total liabilities	$	884	$	86	$	643	$	155

Business Acquisition, Pro Forma Information


	For the Year Ended December 31,
(In millions)	2021		2020		2019
Total operating revenues	$	26,987	$	21,326	$	23,673
Income from continuing operations	2,225		471		3,623

Summary of Results of Discontinued Operations

Summarized results of South Central discontinued operations for the year ended December 31, 2019 were as follows:


	(In millions)
Operating revenues	$	31
Operating costs and expenses	(23)



Gain from operations of discontinued components	8
Gain on disposal of discontinued operations, net of tax	20
Gain from discontinued operations, including disposal, net of tax	$	28

Summarized results of NRG Yield, Inc. and Renewables Platform and Carlsbad discontinued operations for the year ended December 31, 2019 were as follows:



	(In millions)
Operating revenues	$	19
Operating costs and expenses	(9)

Other expenses	(5)


Gain/(loss) from discontinued operations, net of tax	5
Gain/(loss) on disposal of discontinued operations, net of tax	265
Income/(expense) from California property tax indemnification	22
Income/(expense) from other commitments, indemnification and fees	4
Income/(loss) on disposal of discontinued operations, net of tax	291
Income/(loss) from discontinued operations, net of tax	$	296

- Definition

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

+ References

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+ Details

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Estimated Carrying Amounts and Fair Values of Financial Instruments Not Carried at Fair Value

The estimated carrying value and fair value of the Company's long-term debt, including current portion, is as follows:


	As of December 31,
	2021				2020
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value



Long-term debt, including current portion (a)	$	8,040	$	8,327	$	8,781	$	9,446

(a) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets

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

The fair values of derivatives assets and liabilities as of the Acquisition Closing Date were as follows:


	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Derivatives assets	$	1,545	$	155	$	1,272	$	118
Derivatives liabilities	1,828		207		1,489		132


	As of December 31, 2021
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	32	$	15	$	17	$	—

Nuclear trust fund investments:
Cash and cash equivalents	33		33		—		—
U.S. government and federal agency obligations	112		111		1		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	44		—		44		—
Corporate debt securities	122		—		122		—
Equity securities	494		494		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Foreign exchange contracts	1		—		1		—
Commodity contracts	7,139		981		5,701		457


Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	99
Equity securities (classified within other non-current assets)	7
Total assets	$	8,188	$	1,635	$	5,990	$	457
Derivative liabilities:
Foreign exchange contracts	$	1	$	—	$	1	$	—
Commodity contracts	$	4,798	$	626	$	4,008	$	164

Total liabilities	$	4,799	$	626	$	4,009	$	164


	As of December 31, 2020
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current or 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 (classified within other non-current assets):
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 (classified within other non-current assets)	8
Total assets	$	1,745	$	597	$	914	$	139
Derivative liabilities:
Commodity contracts	$	884	$	86	$	643	$	155

Total liabilities	$	884	$	86	$	643	$	155

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


	For the Year Ended December 31, 2021
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
(In millions)	Derivatives (a)
Beginning balance as of January 1, 2021	$	(16)
Contracts added from Direct Energy acquisition	(15)

Total gains realized/unrealized included in earnings	145


Purchases	93

Transfers into Level 3 (b)	71
Transfers out of Level 3 (b)	15
Ending balance as of December 31, 2021	$	293
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, 2021	$	120

(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, 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

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, 2021 and 2020:


	Significant Unobservable Inputs
	December 31, 2021
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Natural Gas Contracts	$	16	$	1	Discounted Cash Flow	Forward Market Price (per MMBtu)	$	3	$	40	$	15
Power Contracts	392		121		Discounted Cash Flow	Forward Market Price (per MWh)	3		212		35
FTRs	49		42		Discounted Cash Flow	Auction Prices (per MWh)	(122)		43		0
	$	457	$	164


	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

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, 2021 and 2020:

Significant Unobservable Input

Position

Change In Input

Impact on Fair Value Measurement

Forward Market Price Natural Gas/ Power

Buy

Increase/(Decrease)

Higher/(Lower)

Forward Market Price Natural Gas/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	67	%
Financial institutions	33


Total	100	%


Category	Net Exposure (a) (b) (% of Total)
Investment grade	55	%
Non-Investment grade/Non-Rated	45

Total	100	%

(a)Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices

(b)The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts

Accounting for Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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


(In millions)		Total Volume
Commodity	Units	December 31, 2021	December 31, 2020
Emissions	Short Ton	1	1
Renewables Energy Certificates	Certificates	13	5
Coal	Short Ton	19	2
Natural Gas	MMBtu	813	(286)
Oil	Barrels	1	—
Power	MWh	185	57
Capacity	MW/Day	—	(1)


Foreign Exchange	Dollars	279	—

The increase in positions is primarily the result of Direct Energy acquisition.

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, 2021		December 31, 2020		December 31, 2021		December 31, 2020






Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Foreign exchange contracts - current	$	—	$	—	$	1	$	—
Foreign exchange contracts - long-term	1		—		—		—

Commodity contracts- current	4,613		560		3,386		499
Commodity contracts- long-term	2,526		261		1,412		385

Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	7,140	$	821	$	4,799	$	884

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, 2021
Foreign exchange contracts:
Derivative assets	$	1	$	(1)	$	—	$	—
Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	$	—	$	—	$	—	$	—
Commodity contracts:
Derivative assets	$	7,139	$	(4,440)	$	(831)	$	1,868
Derivative liabilities	(4,798)		4,440		17		(341)
Total commodity contracts	$	2,341	$	—	$	(814)	$	1,527






Total derivative instruments	$	2,341	$	—	$	(814)	$	1,527


	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)

Pre-tax Effects of Economic Hedges That Have Not Been Designated As Cash Flow Hedges, Ineffectiveness On Cash Flow Hedges And Trading Activity on the Company's Statement of Operations


	Year Ended December 31,
(In millions)	2021		2020		2019
Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(41)	$	(55)	$	(68)
Reversal of acquired loss positions related to economic hedges	256		4		6
Net unrealized gains/(losses) on open positions related to economic hedges	2,501		(68)		42
Total unrealized mark-to-market gains/(losses) for economic hedging activities	2,716		(119)		(20)
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity	(18)		(20)		(11)
Reversal of acquired (gain) positions related to trading activity	(1)		—		—

Net unrealized (losses)/gains on open positions related to trading activity	(13)		15		31
Total unrealized mark-to-market (losses)/gains for trading activity	(32)		(5)		20
Total unrealized gains/(losses)	$	2,684	$	(124)	$	—


	Year Ended December 31,
(In millions)	2021		2020		2019
Unrealized (losses)/gains included in operating - commodities	$	(196)	$	90	$	53
Unrealized gains/(losses) included in cost of operations- commodities	2,880		(214)		(53)
Total impact to statement of operations- commodities	$	2,684	$	(124)	$	—
Total impact to statement of operations — interest rate contracts	$	—	$	—	$	(38)

Nuclear Decommissioning Trust Fund (Tables)

12 Months Ended

Dec. 31, 2021

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


	As of December 31, 2021							As of December 31, 2020
(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	$	33	$	—	$	—	—	$	23	$	—	$	—	—
U.S. government and federal agency obligations	112		5		1		10	70		6		—		10
Federal agency mortgage-backed securities	100		2		—		25	89		4		—		24
Commercial mortgage-backed securities	44		1		—		27	36		2		—		27
Corporate debt securities	122		7		1		14	144		13		—		12
Equity securities	593		456		—		—	521		372		—		—
Foreign government fixed income securities	4		—		—		13	7		1		—		10
Total	$	1,008	$	471	$	2		$	890	$	398	$	—

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


	Year Ended December 31,
(In millions)	2021		2020		2019
Realized gains	$	47	$	34	$	18
Realized (losses)	(9)		(13)		(9)
Proceeds from sale of securities	710		439		381

Inventory (Tables)

12 Months Ended

Dec. 31, 2021

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of:


	As of December 31,
(In millions)	2021		2020
Fuel oil	$	8	$	37
Coal	83		73
Natural gas	206		22
Spare parts and finished goods	201		195
Total Inventory	$	498	$	327

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2021

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)	2021		2020		Lives
Facilities and equipment	$	1,742	$	3,365	1-40 years
Land and improvements	271		329
Nuclear fuel	222		239		5 years
Hardware and office equipment and furnishings	637		453		2-10 years
Construction in progress	124		97
Total property, plant, and equipment	2,996		4,483
Accumulated depreciation	(1,308)		(1,936)
Net property, plant, and equipment	$	1,688	$	2,547

Leases (Tables)

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Lease Cost

Lease Cost:


	For the Year Ended December 31,
(In millions)	2021		2020		2019
Finance lease cost	$	4	$	3	$	—


Operating lease cost	91		100		109
Short-term lease cost	3		3		3
Variable lease cost	9		6		6
Sublease income	(2)		(17)		(17)
Total lease cost	$	105	$	95	$	101

Other information:


	For the Year Ended December 31,
(In millions)	2021		2020		2019

Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	102	$	101	$	104

Financing cash flows from finance leases	6		1		—
Right-of-use assets obtained in exchange for new finance lease liabilities	16		5		—
Right-of-use assets obtained in exchange for new operating lease liabilities	47		4		215

Lease Term and Discount Rate for leases:


	December 31, 2021		December 31, 2020
Finance leases:
Weighted average remaining lease term (in years)	3.6		1.1
Weighted average discount rate	2.46	%	4.79	%

Operating leases:
Weighted average remaining lease term (in years)	4.7		5.3
Weighted average discount rate	5.44	%	5.63	%

Schedule of Annual Payments Based on Maturities of Leases

As of December 31, 2021, annual payments based on the maturities of NRG's operating leases are expected to be as follows:


	In millions
2022	$	96
2023	89
2024	76
2025	52
2026	11
Thereafter	48
Total undiscounted lease payments	$	372
Less: present value adjustment	(55)
Total discounted lease payments	$	317

Goodwill and Other Intangibles (Tables)

12 Months Ended

Dec. 31, 2021

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

Goodwill did not change during the year ended December 31, 2020.


(in millions)	Texas		East		West/Services/Other		Total
Balance as of January 1, 2021	$	324	$	240	$	15	$	579
Goodwill resulted from the acquisition of Direct Energy	427		648		175		1,250
Impairment losses	—		(35)		—		(35)
Foreign currency translation	—		—		1		1
Balance as of December 31, 2021	$	751	$	853	$	191	$	1,795

Summary of the Components of Intangible Assets Subject to Amortization

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


(In millions)
Year Ended December 31, 2021	Emission Allowances		Customer and Supply Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other(b)		Total
January 1, 2021	$	672	$	28	$	527	$	285	$	373	$	140	$	2,025
Purchases	10		—		—		—		—		338		348
Acquisition of businesses (a)	—		610		1,308		—		310		124		2,352
Usage/Sales/Retirements	(1)		—		—		—		—		(364)		(365)
Write-off of fully amortized balances	(51)		—		(158)		—		—		(7)		(216)

Other	4		—		2		(1)		—		(2)		3
December 31, 2021	634		638		1,679		284		683		229		4,147
Less accumulated amortization	(536)		(94)		(518)		(123)		(294)		(71)		(1,636)
Net carrying amount	$	98	$	544	$	1,161	$	161	$	389	$	158	$	2,511

(b)RECs are not subject to amortization and had a carrying value of $123 million


(In millions)
Year Ended December 31, 2020	Emission Allowances		Customer and Supply Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other(b)		Total
January 1, 2020	$	662	$	28	$	573	$	285	$	373	$	130	$	2,051
Purchases	25		—		—		—		—		45		70
Acquisition of businesses (a)	—		—		22		—		—		—		22
Usage/Retirements	—		—		—		—		—		(35)		(35)
Write-off of fully amortized balances	(4)		—		(70)		—		—		—		(74)
Impairment	(14)		—		—		—		—		—		(14)
Other	3		—		2		—		—		—		5
December 31, 2020	672		28		527		285		373		140		2,025
Less accumulated amortization	(563)		(28)		(349)		(99)		(247)		(71)		(1,357)
Net carrying amount	$	109	$	—	$	178	$	186	$	126	$	69	$	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

Schedule of Amortization and Retirements of Intangible Expense

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


	Years Ended December 31,
(In millions)	2021		2020		2019
Emission allowances	$	24	$	28	$	32
Customer and supply contracts	66		12		14
Customer relationships	327		74		44
Marketing partnerships	24		24		15
Trade names	47		27		25
Other(a)	7		3		4
Total amortization	$	495	$	168	$	134

(a)For the years ended December 31, 2021, 2020 and 2019, other intangibles were amortized to depreciation and amortization expense for $3 million, $3 million and $4 million, respectively

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, 2021 for each of the next five years:


(In millions)
Year Ended December 31,	Emission Allowances		Customer and Supply Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other		Total
2022	$	14	$	143	$	265	$	23	$	47	$	3	$	495
2023	12		120		216		23		46		4		421
2024	12		73		148		23		38		3		297
2025	11		50		110		22		32		4		229
2026	9		52		95		22		24		4		206

Long-term Debt and Finance Leases (Tables)

12 Months Ended

Dec. 31, 2021

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, 2021		December 31, 2020		Interest rate %

Recourse debt:
Senior Notes, due 2026	$	—	$	1,000	7.250
Senior Notes, due 2027	375		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		500		3.375
Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	1,100		—		3.875
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		500		2.000
Senior Secured First Lien Notes, due 2027	900		900		2.450
Senior Secured First Lien Notes, due 2029	500		500		4.450

Tax-exempt bonds	466		466		1.250 - 4.750




Subtotal long-term debt (including current maturities)	8,100		8,855
Finance leases	13		4		various

Subtotal long-term debt and finance leases (including current maturities)	8,113		8,859
Less current maturities	(4)		(1)
Less debt issuance costs	(83)		(93)
Discounts	(60)		(74)
Total long-term debt and finance leases	$	7,966	$	8,691

Debt includes the following discounts:


	As of December 31,
(In millions)	2021		2020
Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029	$	(2)	$	(2)
Convertible Senior Notes, due 2048	(58)		(72)
Total discounts	$	(60)	$	(74)

Annual Payments Based On the Maturities of NRG's Debt

As of December 31, 2021, annual payments based on the maturities of NRG's debt and finance leases are expected to be as follows:


	(In millions)
2022	$	4
2023	3
2024	603
2025	502
2026	—
Thereafter	7,001
Total	$	8,113

Senior Note Redemptions


(In millions, except percentages)	Principal Repurchased		Cash Paid(a)		Average Early Redemption Percentage
7.250% Senior Notes, due 2026	$	1,000	$	1,056	103.625	%
6.625% Senior Notes, due 2027	855		893		103.313	%
Total	$	1,855	$	1,949

(a) Includes accrued interest of $29 million for redemptions for the year ended December 31, 2021


Redemption Period	Redemption Percentage
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	%

In addition, on or after January 15, 2023, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Redemption Period	Redemption Percentage
January 15, 2023 to January 14, 2024	102.875	%
January 15, 2024 to January 14, 2025	101.917	%
January 15, 2025 to January 14, 2026	100.958	%
January 15, 2026 and thereafter	100.000	%

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	%

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	%

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	%

In addition, on


Year	Redemption Percentage (If Sustainability Performance Target has been satisfied and confirmed by External Verifier)		Redemption Percentage (If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)
2027	101.938	%	102.188	%
2028	101.292	%	101.458	%
2029	100.646	%	100.729	%
2030 and thereafter	100.000	%	100.000	%

Schedule of Tax Exempt Bonds

Tax Exempt Bonds


	As of December 31,
(In millions, except rates)	2021		2020		Interest Rate %
NRG Indian River Power 2020, tax exempt bonds, due 2040	$	57	$	57	1.250
NRG Indian River Power 2020, tax exempt bonds, due 2045	190		190		1.250
NRG Dunkirk 2020, tax exempt bonds, due 2042	59		59		1.300
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

- Definition

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

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+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

Schedule of ARO Obligations and Related Additions, Reductions and Accretion


(In millions)	Nuclear Decommission		Other(a)		Total
Balance as of December 31, 2020	$	303	$	457	$	760
Revisions in estimates for current obligations	—		(36)		(36)
Additions	—		5		5
Spending for current obligations	—		(51)		(51)
Accretion	18		24		42
Balance as of December 31, 2021	$	321	$	399	$	720

Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2021

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)	2021		2020		2019
Service cost benefits earned	$	9	$	10	$	10
Interest cost on benefit obligation	27		38		46
Expected return on plan assets	(66)		(61)		(59)
Amortization of unrecognized net loss	1		5		3
Settlement/curtailment expense	2		—		—
Net periodic benefit (credit)/cost	$	(27)	$	(8)	$	—


	Year Ended December 31,
	Other Postretirement Benefits
(In millions)	2021		2020		2019
Service cost benefits earned	$	—	$	—	$	1
Interest cost on benefit obligation	2		3		3
Amortization of unrecognized prior service cost	(10)		(14)		(13)
Amortization of unrecognized net loss	1		1		—
Curtailment loss	1		—		—
Net periodic benefit credit	$	(6)	$	(10)	$	(9)

Schedule of Comparison of Pension Benefit obligation, Other Postretirement Benefit Obligations and Related Plan Assets on a Combined Basis

A comparison of the pension benefit obligation, other postretirement benefit obligations and related plan assets for NRG's plans on a combined basis is as follows:


	As of December 31,
	Pension Benefits				Other Postretirement Benefits
(In millions)	2021		2020		2021		2020
Benefit obligation at January 1	$	1,489	$	1,397	$	90	$	93
Acquired benefit obligation from Direct Energy	74		—		19		—
Service cost	9		10		—		—
Interest cost	27		38		2		3

Actuarial (gain)/loss	(55)		126		—		—
Employee and retiree contributions	—		—		3		3
Curtailment loss	—		—		1		—
Benefit payments	(93)		(82)		(10)		(9)
Foreign exchange translation	1		—		—		—
Benefit obligation at December 31	1,452		1,489		105		90
Fair value of plan assets at January 1	1,272		1,150		—		—
Acquired fair value of plan assets from Direct Energy	64		—				—
Actual return on plan assets	85		193		—		—
Employee and retiree contributions	—		—		3		3
Employer contributions	7		11		7		6
Benefit payments	(93)		(82)		(10)		(9)
Foreign exchange translation	1		—		—		—
Fair value of plan assets at December 31	1,336		1,272		—		—
Funded status at December 31 — excess of obligation over assets	$	(116)	$	(217)	$	(105)	$	(90)

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)	2021		2020		2021		2020
Other current liabilities	$	—	$	—	$	7	$	5
Other non-current liabilities	116		217		98		85

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)	2021		2020		2021		2020
Net loss	$	52	$	127	$	5	$	6
Prior service cost/(credit)	2		2		(19)		(29)
Total accumulated OCI	$	54	$	129	$	(14)	$	(23)

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)	2021		2020		2021		2020
Net actuarial gain	$	(72)	$	(6)	$	—	$	—
Amortization of net actuarial loss	(1)		(5)		(1)		(1)


Amortization of prior service cost	—		—		10		14
Effect of settlement	(2)		—		—		—
Total recognized in OCI	$	(75)	$	(11)	$	9	$	13
Net periodic benefit credit	(27)		(8)		(6)		(10)
Net recognized in net periodic pension credit and OCI	$	(102)	$	(19)	$	3	$	3

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)	2021		2020
Projected benefit obligation	$	1,452	$	1,489
Accumulated benefit obligation	1,423		1,455
Fair value of plan assets	1,336		1,272

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


	Fair Value Measurements as of December 31, 2021
(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	$	—	$	221	$	221
Common/collective trust investment — non-U.S. equity	—		69		69
Common/collective trust investment — non-core assets	—		110		110
Common/collective trust investment — fixed income	—		340		340
Short-term investment fund	13		—		13
Subtotal fair value	$	13	$	740	$	753
Measured at net asset value practical expedient:
Common/collective trust investment — non-U.S. equity					78
Common/collective trust investment — fixed income					405
Common/collective trust investment — non-core assets					65
Partnerships/joint ventures					35
Total fair value					$	1,336


	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

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	2021		2020		2021		2020
Discount rate	2.89	%	2.56	%	2.89	%	2.54	%
Interest crediting rate	3.07	%	3.12	%	1.94	%	1.62	%
Rate of compensation increase	3.06	%	3.00	%	—	%	—	%
Health care trend rate	—		—		6.8% grading to 4.4% in 2028		7.2% 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	2021		2020		2019		2021		2020		2019
Discount rate	2.55	%	3.26	%	4.38%/4.20%		2.81%		3.26	%	4.37	%
Interest crediting rate	3.13	%	3.66	%	—		1.62	%	2.28	%	—
Expected return on plan assets	5.62	%	5.93	%	6.35	%	—		—		—
Rate of compensation increase	3.06	%	3.00	%	3.00	%	—		—		—
Health care trend rate	—		—		—		7.0% grading to 4.4% in 2028		7.5% grading to 4.5% in 2028		7.8% 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, 2021:


U.S. equity	17	%
Non-U.S. equity	13	%
Non-core assets	15	%
Fixed Income	55	%

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 Index
Non-core assets(a)						Various (per underlying asset class)
Fixed income securities						Barclays Short, Intermediate and Long Credits/Barclays Strips 20+ Index and FTSE Canada Universe Bond 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
2022	$	96	$	7	$	—
2023	94		7		—
2024	91		7		—
2025	87		6		—
2026	86		6		—
2027-2031	396		26		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)	2021		2020		2021		2020
Funded status — STPNOC benefit plans	$	(50)	$	(99)	$	(18)	$	(20)
Net periodic benefit cost/(credit)	17		7		(4)		(4)
Other changes in plan assets and benefit obligations recognized in other comprehensive income	(51)		22		4		5

Defined Contribution Plan Contributions

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


	Year Ended December 31,
(In millions)	2021		2020		2019
Company contributions to defined contribution plans	$	25	$	22	$	22

Capital Structure (Tables)

12 Months Ended

Dec. 31, 2021

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 Shares
	Issued	Treasury	Outstanding
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
Shares issued under ESPP	—	117,392	117,392
Shares issued under LTIPs	489,326	—	489,326
Share repurchases	—	(1,084,752)	(1,084,752)
Balance as of December 31, 2021	423,547,174	(179,793,275)	243,753,899
Shares issued under LTIPs	288,491	—	288,491
Share repurchases	—	(1,889,151)	(1,889,151)
Balance as of February 24, 2022	423,835,665	(181,682,426)	242,153,239

Summary of shares repurchased

The following table summarizes the shares repurchases made during the years ended December 31, 2019, 2020 and 2021 as well as through February 24, 2022:


	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)


2019 repurchases:
Repurchases under February 28, 2019 Accelerated Share Repurchase Agreement	9,438,671			400
Other repurchases(a)	26,863,211			1,008
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	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(b)	711,248			27
Total Share Repurchases during 2020	6,774,031	$	33.05	$	224
2021 repurchases:
Repurchases(a)	1,084,752			44
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	249,013			9
Total Share Repurchases during 2021	1,333,765	$	40.22	$	53
2022 repurchases:
Repurchases made subsequent to December 31, 2021	1,889,151			76
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	130,674			6
Total share repurchases January 1, 2021 through February 24, 2022	2,019,825	$	40.26	$	82

(a)Includes $5 million and $4 million accrued as of December 31, 2021 and December 31,2019, respectively

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

12 Months Ended

Dec. 31, 2021

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, 2021:


(In millions, except percentages)
Name:	Economic Interest		Investment Balance(a)
Gladstone	37.5	%	$	127
Ivanpah Master Holdings, LLC	54.5	%	4
Watson Cogeneration Company	49.0	%	14
Midway-Sunset Cogeneration Company	50.0	%	12
Total equity investments in affiliates			$	157
Petra Nova Parish Holdings, LLC(b)	50.0	%	$	(16)

Undistributed earnings by equity investment


	As of December 31,
(In millions)	2021		2020
Undistributed earnings from equity investments	$	33	$	30

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, 2021		December 31, 2020
Accounts receivable	$	939	$	647
Other current assets	—		2


Total assets	939		649
Current liabilities	78		78




Net assets	$	861	$	571

Income Per Share (Tables)

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Reconciliation of NRG's basic and diluted income per share

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


	Year Ended December 31,
(In millions, except per share amounts)	2021		2020		2019
Basic income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. common stockholders	$	2,187	$	510	$	4,438



Weighted average number of common shares outstanding-basic	245		245		262
Income per weighted average common share — basic	$	8.93	$	2.08	$	16.94
Diluted income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. common stockholders	$	2,187	$	510	$	4,438
Weighted average number of common shares outstanding-basic	245		245		262
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—		1		2
Weighted average number of common shares outstanding-diluted	245		246		264
Income per weighted average common share — diluted	$	8.93	$	2.07	$	16.81

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Segment Reporting


	For the Year Ended December 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate(a)		Eliminations		Total
Operating revenues(a)	$	10,293	$	13,033	$	3,653	$	—	$	10	$	26,989
Operating expenses	8,692		10,257		3,466		141		10		22,566
Depreciation and amortization	331		338		88		28		—		785
Impairment losses	—		535		9		—		—		544
Total operating cost and expenses	9,023		11,130		3,563		169		10		23,895

Gain on sale of assets	19		—		17		211		—		247
Operating income	1,289		1,903		107		42		—		3,341
Equity in (losses)/earnings of unconsolidated affiliates	(3)		—		20		—		—		17

Other income, net	8		7		3		59		(14)		63
Loss on debt extinguishment	—		—		—		(77)		—		(77)
Interest expense	(1)		(1)		(28)		(469)		14		(485)
Income/(loss) from continuing operations before income taxes	1,293		1,909		102		(445)		—		2,859
Income tax expense	—		—		19		653		—		672




Net income/(loss) attributable to NRG Energy, Inc.	$	1,293	$	1,909	$	83	$	(1,098)	$	—	$	2,187

Balance sheet
Equity investments in affiliates	$	—	$	—	$	157	$	—	$	—	$	157
Capital expenditures	153		50		21		45		—		269
Goodwill	751		853		191		—		—		1,795
Total assets	$	12,265	$	13,673	$	4,816	$	19,081	$	(26,653)	$	23,182


(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues			$	5					$	(18)					$	3					$	—					$	—					$	(10)


	For the Year Ended December 31, 2020
(In millions)	Texas		East		West/Services/Other		Corporate(a)		Eliminations		Total
Operating revenues(a)	$	6,309	$	2,258	$	530	$	—	$	(4)	$	9,093
Operating expenses	5,249		1,758		421		57		(4)		7,481
Depreciation and amortization	227		138		36		34		—		435
Impairment losses	14		—		61		—		—		75
Total operating cost and expenses	5,490		1,896		518		91		(4)		7,991

(Loss)/gain on sale of assets	—		—		(2)		5		—		3
Operating income/(loss)	819		362		10		(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	800		351		39		(429)		—		761
Income tax (benefit)/expense	—		(1)		2		250		—		251




Net income attributable to NRG Energy, Inc.	$	800	$	352	$	37	$	(679)	$	—	$	510

Balance sheet
Equity investments in affiliates	$	(13)	$	—	$	359	$	—	$	—	$	346
Capital expenditures	130		45		30		25		—		230
Goodwill(b)	324		240		15		—		—		579
Total assets	$	7,641	$	1,790	$	1,679	$	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/Services/Other		Corporate(a)		Eliminations		Total
Operating revenues(a)	$	7,069	$	2,262	$	497	$	—	$	(7)	$	9,821
Operating expenses	5,821		1,843		453		50		(7)		8,160
Depreciation and amortization	188		117		37		31		—		373
Impairment losses	1		—		4		—		—		5
Total operating cost and expenses	6,010		1,960		494		81		(7)		8,538

Gain on sale of assets	—		1		—		6		—		7
Operating income/(loss)	1,059		303		3		(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		291		6		(483)		—		786
Income tax expense/(benefit)	—		2		1		(3,337)		—		(3,334)
Net income from continuing operations	972		289		5		2,854		—		4,120
Gain from discontinued operations, net of income tax	—		—		—		321		—		321
Net Income	972		289		5		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	$	289	$	2	$	3,175	$	—	$	4,438


(a) Inter-segment sales and inter-segment net derivative gains and losses included in operating revenues			$	1					$	8					$	(2)					$	—					$	—					$	7

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

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)	2021			2020			2019
Current

State	$	48		$	22		$	2
Foreign	3			4			4
Total — current	51			26			6
Deferred
U.S. Federal	569			168			(3,000)
State	36			60			(340)
Foreign	16			(3)			—
Total — deferred	621			225			(3,340)
Total income tax expense/(benefit)	$	672		$	251		$	(3,334)
Effective income tax rate	23.5		%	33.0		%	(424.2)		%

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)	2021		2020		2019
U.S.	$	2,759	$	749	$	771
Foreign	100		12		15
Total	$	2,859	$	761	$	786

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)	2021			2020			2019
Income from continuing operations before income taxes	$	2,859		$	761		$	786
Tax at federal statutory tax rate	600			160			165
Foreign rate differential	(3)			—			—
State taxes	111			18			13

Permanent differences	8			8			(9)
Changes in valuation allowance	(29)			24			(3,492)


Deferred impact of state tax rate changes	(10)			2			12

Recognition of uncertain tax benefits	(10)			3			(10)
Return to provision adjustments	5			36			—




Other	—			—			(13)
Income tax expense/(benefit)	$	672		$	251		$	(3,334)
Effective income tax rate	23.5		%	33.0		%	(424.2)		%

Company's deferred tax assets and liabilities

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


	As of December 31,
(In millions)	2021		2020
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	$	114	$	79
Difference between book and tax basis of property	436		357


Pension and other postretirement benefits	65		86
Equity compensation	7		10
Bad debt reserve	168		16
Derivatives, net	—		11
U.S. Federal net operating loss carryforwards	1,773		2,117
Foreign net operating loss carryforwards	112		102
State net operating loss carryforwards	328		351

Federal and state tax credit carryforwards	384		384
Federal benefit on state uncertain tax positions	3		4

Interest disallowance carryforward per §163(j) of the Tax Act	6		4
Inventory obsolescence	9		6
Other	15		10

Total deferred tax assets	3,420		3,537
Deferred tax liabilities:
Emissions allowances	20		21


Derivatives	591		—
Goodwill	40		29
Intangibles amortization (excluding goodwill)	363		2
Equity method investments	62		156

Convertible Debt	14		16


Total deferred tax liabilities	1,090		224
Total deferred tax assets less deferred tax liabilities	2,330		3,313
Valuation allowance	(248)		(266)

Total net deferred tax assets, net of valuation allowance	$	2,082	$	3,047

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)	2021		2020
Deferred tax asset	$	2,155	$	3,066

Deferred tax liability	(73)		(19)
Net deferred tax asset	$	2,082	$	3,047

Reconciliation of total amounts of uncertain tax benefits

The following table summarizes uncertain tax benefits activity:


	As of December 31,
(In millions)	2021		2020
Balance as of January 1	$	15	$	15
Increase due to current year positions	4		3
Increase due to acquired balance from Direct Energy	9		—

Settlements, payments and statute closure	(15)		(3)
Uncertain tax benefits as of December 31	$	13	$	15

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2021

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, 2020	519,514	$	35.87
Granted	479,415	39.00
Forfeited	(49,816)	37.41
Vested	(279,161)	34.18

Non-vested at December 31, 2021	669,952	38.69

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, 2020	342,706	$	25.37
Granted	64,512	32.27

Converted to Common Stock	(23,090)	30.92

Outstanding at December 31, 2021	384,128	26.11

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, 2020	793,561	$	41.69
Granted	426,768	46.78
Forfeited	(93,031)	47.21
Vested	(396,793)	35.32
Non-vested at December 31, 2021	730,505	47.40

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:


	2021(a)		2020		2019
	RPSUs		RPSUs		RPSUs
Expected volatility	34.05	%	30.15	%	40.72	%
Expected term (in years)	3		3		3
Risk free rate	0.17	%	1.58	%	2.45	%

(a) Assumptions pertain to the main award granted in January 2021. Additional 60,815 RPSUs were granted in September 2021 with a risk free rate of 0.42% and expected volatility of 37.38%

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, 2020	77,047	$	25.13	0.5	$	1
Expired	(4,800)	29.08
Exercised	(54,377)	26.44
Outstanding at December 31, 2021	17,870	20.07		0.2	—
Exercisable at December 31, 2021	17,870	20.07		0.2	—

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)	2021		2020		2019

Total intrinsic value of options exercised	$	1	$	1	$	2
Cash received from options exercised	1		1		3

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


							Non-vested Compensation Cost
(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	2021		2020		2019		2021		2021

RSUs	$	9	$	9	$	9	$	16	1.80
DSUs	2		2		2		—		0.00

RPSUs	9		10		10		15		1.19
PRSUs(a)	7		6		11		10		1.52
Total	$	27	$	27	$	32	$	41
Tax detriment/(benefit) recognized	$	2	$	(9)	$	(12)

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2021

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)	2021		2020		2019
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	4	$	4	$	4
Ivanpah(a)	39		43		35
Midway-Sunset	6		5		5
Total	$	49	$	52	$	44

(a)Includes fees under project management agreements with each project company

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Commitments under coal, gas and transportation contractual agreements

As of December 31, 2021, the Company's minimum commitments under such outstanding agreements are estimated as follows:


Period	(In millions)
2022	$	122
2023	54
2024	63
2025	62
2026	51
Thereafter	26
Total(a)	$	378

(a)Actual fuel and transportation purchases are significantly higher than these estimated minimum unconditional long-term firm commitments with remaining term in excess of one year

Minimum purchase commitment obligations under purchased power agreements

These contracts are not included in the consolidated balance sheet as of December 31, 2021. Minimum purchase commitment obligations are as follows as of December 31, 2021:


Period	(In millions)
2022	$	1,566
2023	1,036
2024	617
2025	382
2026	289
Thereafter	1,071
Total(a)	$	4,961

(a)Actual energy purchases are significantly higher than these estimated minimum unconditional long-term firm commitments with remaining term in excess of one year

Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2021

Supplemental Cash Flow Information [Abstract]

Details of supplemental disclosures of cash flow and non-cash investing and financing information


	Year Ended December 31,
(In millions)	2021		2020		2019
Cash and cash equivalents	$	250	$	3,905	$	345
Funds deposited by counterparties	845		19		32
Restricted cash	15		6		8
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$	1,110	$	3,930	$	385

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


	Year Ended December 31,
(In millions)	2021		2020		2019
Interest paid, net of amount capitalized	$	433	$	340	$	372
Income taxes paid, net of refunds	32		24		8
Non-cash investing activities:
(Decreases)/additions to fixed assets for accrued capital expenditures	(16)		(6)		1

Guarantees (Tables)

12 Months Ended

Dec. 31, 2021

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)	2021
Guarantees	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2020 Total
Letters of credit and surety bonds	$	4,064	$	31	$	—	$	—	$	4,095	$	1,153
Asset sales guarantee obligations	269		25		24		96		414		506
Other guarantees	—		—		—		93		93		87
Total guarantees	$	4,333	$	56	$	24	$	189	$	4,602	$	1,746

Jointly Owned Plants (Tables)

12 Months Ended

Dec. 31, 2021

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, 2021	Ownership Interest		Property, Plant & Equipment		Accumulated Depreciation		Construction in Progress
South Texas Project Units 1 and 2, Bay City, TX	44.00	%	$	421	$	(208)	$	4
Cedar Bayou Unit 4, Baytown, TX	50.00	%	220		(109)		12

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Tables)

12 Months Ended

Dec. 31, 2021

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, 2021	$	67	$	698	$	112	$	(194)	(a)	$	683
Year Ended December 31, 2020	43		108		—		(84)		(a)	67
Year Ended December 31, 2019	32		95		—		(84)		(a)	43
Income tax valuation allowance, deducted from deferred tax assets
Year Ended December 31, 2021	$	266	$	(29)	$	11	$	—		$	248
Year Ended December 31, 2020	242		24		—		—			266
Year Ended December 31, 2019	3,794		(3,543)		(9)		—			242

(a) Represents principally net amounts charged as uncollectible

Nature of Business (Details) customer in Millions, $ in Millions				12 Months Ended
	Dec. 06, 2021 USD ($) MW	Dec. 01, 2021 USD ($) MW	Jan. 05, 2021 customer state	Dec. 31, 2021 customer MW	Jun. 30, 2021 MW	Jan. 05, 2021 province	Aug. 01, 2019 state
Business Acquisition [Line Items]
Generation capacity (in MW)				18,000
Number of states in which the entity operates \| state							9
PJM Coal Generating Assets
Business Acquisition [Line Items]
Generation capacity (in MW)					1,600
East/West Other \| Arthur Kill Plant
Business Acquisition [Line Items]
Generation capacity (in MW)	866	866
East/West Other \| Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations
Business Acquisition [Line Items]
Generation capacity (in MW)		4,850
Proceeds from sale of, net of working capital adjustments \| $	$ 623	$ 623
Direct Energy
Business Acquisition [Line Items]
Customers served (over) \| customer			3
Direct Energy \| U.S.
Business Acquisition [Line Items]
Number of states in which the entity operates \| state			50
Direct Energy \| Canada
Business Acquisition [Line Items]
Provinces in which entity operates			8			8
Home
Business Acquisition [Line Items]
Customers served (over) \| customer				6

Summary of Significant Accounting Policies - Additional (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jun. 30, 2022
Funds Deposited by Counterparties
Number of months beyond which company can not predict the holding of collateral (in months)	12 months
Securitization Receivable [Abstract]
Uplift securitization proceeds receivable from ERCOT	$ 689	$ 0
Project Development Costs and Capitalized Interest
Amount of interest capitalized	2	2	$ 3
Finite-Lived Intangible Assets, Net [Abstract]
Intangible assets, accumulated amortization	$ 1,636	1,357
Lease Revenue
Lease term	20 years
Gross Receipts and Sales Taxes
Gross Receipts Tax	$ 184	107	109
Purchased Energy and Other Cost of Sales for Customer Operations
Transmission and distribution charges not yet billed	189	98	103
Foreign Currency Translation and Transaction Gains and Losses
Cumulative translation adjustment	(8)	(2)	(13)
Marketing and Advertising Costs
Advertising expense	$ 109	$ 74	$ 66
Subsequent Event \| Scenario, Forecast
Securitization Receivable [Abstract]
Uplift securitization proceeds receivable from ERCOT				$ 689
South Texas Project
Property, Plant and Equipment
Ownership Interest (as a percent)	44.00%

Summary of Significant Accounting Policies - Activity in the Allowance for Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 67	$ 43
Acquired balance from Direct Energy	112	0
Provision for credit losses	698	108	$ 95
Write-offs	(224)	(101)
Recoveries collected	30	17
Ending balance	683	$ 67	$ 43
Increase in provision for credit losses due to impacts of Winter Storm Uri on bilateral finance hedging risk	403
Increase to provision due to counterparty credit risk	126
Increase to provision due to shortfall payments	$ 67

Summary of Significant Accounting Policies - Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Cash and cash equivalents	$ 250	$ 3,905	$ 345
Funds deposited by counterparties	845	19	32
Restricted cash	15	6	8
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$ 1,110	$ 3,930	$ 385	$ 613

Summary of Significant Accounting Policies - Redeemable Non Controlling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Noncontrolling Interest [Roll Forward]
Balance at beginning of period	$ 20	$ 19
Net income attributable to redeemable noncontrolling interest - continuing operations		3
Repurchase of redeemable noncontrolling interest	(20)
Balance at end of period	$ 0	20
Redeemable noncontrolling interest
Noncontrolling Interest [Roll Forward]
Distributions to redeemable noncontrolling interest		$ (2)

Summary of Significant Accounting Policies - Recent Accounting Developments (Details) - USD ($) $ in Millions	Jan. 01, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity		$ 3,600	$ 1,680	$ 1,658	$ (1,234)
Deferred tax liabilities		(1,090)	(224)
Cumulative Effect, Period of Adoption, Adjustment \| Subsequent Event
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt Instrument, Unamortized Discount	$ 57
Deferred tax liabilities	14
Additional Paid-In Capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity		8,531	8,517	8,501	8,510
Additional Paid-In Capital \| Cumulative Effect, Period of Adoption, Adjustment \| Subsequent Event
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity	(100)
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity		$ 464	$ (1,403)	$ (1,616)	$ (6,022)
Retained Earnings \| Cumulative Effect, Period of Adoption, Adjustment \| Subsequent Event
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Stockholders' equity	$ 57

- Definition

Amount of stockholders' equity (deficit), net of receivables from officers, directors, owners, and affiliates of the entity, attributable to both the parent and noncontrolling interests. Amount excludes temporary equity. Alternate caption for the concept is permanent equity.

+ References

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+ Details

Revenue Recognition - Capacity Revenue (Details) $ in Millions	Dec. 31, 2021 USD ($)
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	$ 258
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	$ 48
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	$ 1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, period	1 year

Revenue Recognition - Disaggregated Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 26,777	$ 8,690	$ 7,991
Mark-to-market for economic hedging activities	2,716	(119)	(20)
Revenues	26,989	9,093	9,821
Less: Lease revenue	8	18	20
Derivative revenue	2,684	(124)	0
Retail Revenue \| Home
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	9,676	6,331	6,254
Retail Revenue \| Business
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	13,885	1,129	1,279
Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	23,561	7,460	7,533
Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,215	539	1,169
Derivative revenue	136	105	1,595
Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	775	680	700
Derivative revenue	149	156	109
Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	(164)	95	33
Derivative revenue	234	385	1,810
Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,632	319	386
Contract amortization	(30)
Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	26,989	9,093	9,821
Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	113	29	73
Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(6)	(7)	(5)
Revenues	10	(4)	(7)
Less: Lease revenue	0	0	0
Corporate/Eliminations \| Retail Revenue \| Home
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(1)	(2)	(3)
Corporate/Eliminations \| Retail Revenue \| Business
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	(1)	(2)	(3)
Corporate/Eliminations \| Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	7	(1)	0
Derivative revenue	3	(5)	(1)
Corporate/Eliminations \| Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	(1)	0
Derivative revenue	0	0	0
Corporate/Eliminations \| Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	13	8	(1)
Derivative revenue	16	3	(2)
Corporate/Eliminations \| Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	(9)	(8)	(3)
Contract amortization	0
Corporate/Eliminations \| Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	10	(4)	(7)
Corporate/Eliminations \| Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	0	0	0
Texas \| Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	10,163	6,279	5,507
Revenues	10,293	6,309	7,069
Less: Lease revenue	0	0	0
Texas \| Operating Segments \| Retail Revenue \| Home
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	5,665	5,027	5,027
Texas \| Operating Segments \| Retail Revenue \| Business
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,745	1,034	1,205
Texas \| Operating Segments \| Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	8,410	6,061	6,232
Texas \| Operating Segments \| Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	329	24	529
Derivative revenue	0	0	1,459
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	(3)	2	47
Derivative revenue	130	30	1,562
Texas \| Operating Segments \| Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,557	222	261
Contract amortization	0
Texas \| Operating Segments \| Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	10,293	6,309	7,069
Texas \| Operating Segments \| Other ancillary revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,300
Texas \| Operating Segments \| Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	133	28	56
Texas \| Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenues	(5)	(6)	(1)
East \| Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	12,874	1,943	2,078
Revenues	13,033	2,258	2,262
Less: Lease revenue	1	1	1
East \| Operating Segments \| Retail Revenue \| Home
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,959	1,210	1,173
East \| Operating Segments \| Retail Revenue \| Business
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	9,903	95	74
East \| Operating Segments \| Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	11,862	1,305	1,247
East \| Operating Segments \| Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	508	183	322
Derivative revenue	131	67	98
East \| Operating Segments \| Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	718	620	664
Derivative revenue	149	156	109
East \| Operating Segments \| Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	(88)	88	(29)
Derivative revenue	184	314	183
East \| Operating Segments \| Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	59	62	58
Contract amortization	(26)
East \| Operating Segments \| Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	13,033	2,258	2,262
East \| Operating Segments \| Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	(8)	3	5
East \| Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenues	18	6	(8)
West/Services/Other \| Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,746	475	411
Less: Lease revenue	7	17	19
West/Services/Other \| Operating Segments \| Retail Revenue \| Home
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,053	96	57
West/Services/Other \| Operating Segments \| Retail Revenue \| Business
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,237	0	0
West/Services/Other \| Operating Segments \| Total retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,290	96	57
West/Services/Other \| Operating Segments \| Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	371	333	318
Derivative revenue	2	43	39
West/Services/Other \| Operating Segments \| Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	57	61	36
Derivative revenue	0	0	0
West/Services/Other \| Operating Segments \| Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	(86)	(3)	16
Derivative revenue	(96)	38	67
West/Services/Other \| Operating Segments \| Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	25	43	70
Contract amortization	(4)
West/Services/Other \| Operating Segments \| Total operating revenues
Disaggregation of Revenue [Line Items]
Revenues	3,653	530	497
West/Services/Other \| Operating Segments \| Other derivative revenue
Disaggregation of Revenue [Line Items]
Derivative revenue	$ (12)	$ (2)	$ 12

Revenue Recognition - Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Schedule Of Contract Assets And Liabilities [Line Items]
Deferred customer acquisition costs	$ 133	$ 113
Accounts receivable, net	3,245	904
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	1,574	393
Deferred revenue	227	60
Deferred revenue from contract with customers	224	31
Revenue recognized	23	13
Accounts receivable, net - Contracts with customers
Schedule Of Contract Assets And Liabilities [Line Items]
Accounts receivable, net	3,057	866
Accounts receivable, net - Derivative instruments
Schedule Of Contract Assets And Liabilities [Line Items]
Accounts receivable, net	182	33
Accounts receivable, net - Affiliate
Schedule Of Contract Assets And Liabilities [Line Items]
Accounts receivable, net	$ 6	$ 5

Acquisitions, Discontinued Operations and Dispositions - Acquisitions (Details) customer in Thousands, $ in Millions				1 Months Ended	12 Months Ended
	Jan. 05, 2021 USD ($) customer state	Sep. 29, 2020 USD ($)	Aug. 01, 2019 USD ($) customer state	Dec. 31, 2020 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Jan. 05, 2021 province
Business Acquisition [Line Items]
Number of states in which the entity operates \| state			9
Acquisition costs					$ 25
Revenues					26,989	$ 9,093	$ 9,821
Income from continuing operations before income taxes					2,859	761	786
Operating lease liability					317
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]
Purchase of assets		$ 260
Direct Energy
Business Acquisition [Line Items]
Customers added (over) \| customer	3,000
Purchase price	$ 3,625
Purchase price adjustment	77				22
Cash paid to acquire business	715
Proceeds from revolving credit facility	166
Acquisition costs	$ 107					$ 17
Proceeds from issuance of secured and unsecured corporate debt				$ 2,900
Revenues					15,600
Income from continuing operations before income taxes					$ 2,400
Direct Energy \| Customer Relationships
Business Acquisition [Line Items]
Intangible assets, useful life	12 years
Direct Energy \| Customer and Supply Contracts
Business Acquisition [Line Items]
Intangible assets, useful life	14 years
Direct Energy \| Trade Names
Business Acquisition [Line Items]
Intangible assets, useful life	15 years
Direct Energy \| U.S.
Business Acquisition [Line Items]
Number of states in which the entity operates \| state	50
Direct Energy \| Canada
Business Acquisition [Line Items]
Provinces in which entity operates	8							8
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

Acquisitions, Discontinued Operations and Dispositions -Collective Collateral Facilities (Details) - USD ($)	Jan. 05, 2021	Jul. 26, 2021	Dec. 31, 2020
Direct Energy
Line of Credit Facility [Line Items]
Revolving credit facility commitment increase	$ 3,400,000,000
Revolving Credit Facility \| Revolving Credit Facility commitment increase
Line of Credit Facility [Line Items]
Revolving credit facility commitment increase	802,000,000
Revolving Credit Facility \| Revolving Credit Facility new tranche
Line of Credit Facility [Line Items]
Revolving credit facilities	273,000,000
Revolving Credit Facility \| Facility agreement in connection with the sale of pre-capitalized trust securities
Line of Credit Facility [Line Items]
Revolving credit facilities	874,000,000
Revolving Credit Facility \| Credit default swap facility
Line of Credit Facility [Line Items]
Revolving credit facilities			$ 150,000,000
Revolving Credit Facility \| Revolving accounts receivable financing facility
Line of Credit Facility [Line Items]
Revolving credit facilities		$ 800,000,000	750,000,000
Revolving Credit Facility \| Repurchase facility
Line of Credit Facility [Line Items]
Revolving credit facilities			75,000,000
Revolving Credit Facility \| Bilateral letter of credit facilities
Line of Credit Facility [Line Items]
Revolving credit facilities			$ 475,000,000
Revolving Credit Facility \| Total Increases to Liquidity and Collateral Facilities
Line of Credit Facility [Line Items]
Revolving credit facility commitment increase	$ 3,399,000,000

Acquisitions, Discontinued Operations and Dispositions - Direct Energy Purchase Price Allocation (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 05, 2021	Dec. 31, 2021	Dec. 31, 2020
Other Assets
Goodwill		$ 1,795	$ 579
Texas
Other Assets
Goodwill	$ 427	751	324
East
Other Assets
Goodwill	648	$ 853	$ 240
West/Services/Other
Other Assets
Goodwill	175
Customer Relationships
Other Liabilities
Weighted average useful life, years		12 years	5 years
Direct Energy
Current Assets
Cash and cash equivalents	152
Funds deposited by counterparties	21
Restricted cash	9
Account receivable	1,802
Inventory	106
Derivative instruments	1,014
Cash collateral paid in support of energy risk management activities	233
Prepayments and other current assets	173
Total current assets	3,510
Property, plant and equipment, net	151
Other Assets
Goodwill	1,250
Intangible assets	2,321
Derivative instruments	531
Other non-current assets	31
Total other assets	4,133
Total Assets	7,794
Current Liabilities
Accounts payable	1,116
Derivative instruments	1,266
Cash collateral received in support of energy risk management activities	21
Accrued expenses and other current liabilities	670
Total current liabilities	3,073
Other Liabilities
Derivative instruments	562
Deferred income taxes	320
Other non-current liabilities	115
Total other liabilities	997
Total Liabilities	4,070
Purchase Price	3,724
Goodwill, expected to be tax deductible	322
Direct Energy \| Customer Relationships
Other Assets
Intangible assets	$ 1,277
Other Liabilities
Weighted average useful life, years	12 years
Direct Energy \| Customer and Supply Contracts
Other Assets
Intangible assets	$ 610
Other Liabilities
Weighted average useful life, years	12 years
Direct Energy \| Trade Names
Other Assets
Intangible assets	$ 310
Other Liabilities
Weighted average useful life, years	12 years
Direct Energy \| Renewable Energy Credits
Other Assets
Intangible assets	$ 124

Acquisitions, Discontinued Operations and Dispositions - Direct Energy Measurement Period Adjustment (Details) - Direct Energy $ in Millions	3 Months Ended
	Dec. 31, 2021 USD ($)
Assets
Prepayments and other current assets	$ (10)
Goodwill	(7)
Total decrease in assets	(17)
Liabilities
Accounts payable	(4)
Accrued expenses and other current liabilities	(20)
Deferred income taxes	(18)
Total decrease in liabilities	(42)
Net measurement period adjustments	$ 25

Acquisitions, Discontinued Operations and Dispositions -Fair Values of Derivatives Assets and Liabilities as of the Acquisition Closing Date (Details) - Direct Energy $ in Millions	Jan. 05, 2021 USD ($)
Derivative [Line Items]
Derivatives assets	$ 1,545
Derivatives liabilities	1,828
Quoted Prices in Active Markets for Identical Assets (Level 1)
Derivative [Line Items]
Derivatives assets	155
Derivatives liabilities	207
Significant Observable Inputs (Level 2)
Derivative [Line Items]
Derivatives assets	1,272
Derivatives liabilities	1,489
Level 3
Derivative [Line Items]
Derivatives assets	118
Derivatives liabilities	$ 132

Acquisitions, Discontinued Operations and Dispositions - Supplemental Pro Forma Financial Information (Details) - Direct Energy - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Business Acquisition [Line Items]
Total operating revenues	$ 26,987	$ 21,326	$ 23,673
Income from continuing operations	$ 2,225	$ 471	$ 3,623

Acquisitions, Discontinued Operations and Dispositions - Purchase Price Allocation (Details) - USD ($) $ in Millions	Dec. 31, 2021	Jan. 05, 2021	Dec. 31, 2020	Aug. 01, 2019
Business Acquisition [Line Items]
Goodwill	$ 1,795		$ 579
Texas
Business Acquisition [Line Items]
Goodwill	751	$ 427	324
East
Business Acquisition [Line Items]
Goodwill	$ 853	$ 648	$ 240
Stream Energy
Business Acquisition [Line Items]
Account receivable				$ 98
Accounts payable				(73)
Other net current and non-current working capital				5
Goodwill				6
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]
Finite-lived intangible assets				154
Stream Energy \| Customer Relationships
Business Acquisition [Line Items]
Finite-lived intangible assets				85
Stream Energy \| Trade Names
Business Acquisition [Line Items]
Finite-lived intangible assets				28
Stream Energy \| Other Intangible Assets
Business Acquisition [Line Items]
Finite-lived intangible assets				$ 26

Acquisitions, Discontinued Operations and Dispositions - Dispositions (Details) $ in Millions						3 Months Ended		12 Months Ended
	Dec. 06, 2021 USD ($) MW	Dec. 01, 2021 USD ($) MW	Aug. 24, 2021 USD ($)	Feb. 03, 2021 USD ($)	Nov. 13, 2020 USD ($)	Dec. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)	Dec. 31, 2021 USD ($) MW	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) \| MW								18,000
Loss on debt extinguishment			$ (77)					$ 77	$ 9	$ 51
Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations \| Indemnification Agreement
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Guarantee (up to)		$ 39
Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations \| Agua Caliente Solar Project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration				$ 202
Percentage of ownership sold				35.00%
Gain on sale				$ 17
Cash disposed				$ 7
Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations \| Home Solar
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale of business					$ (2)
Proceeds from sale					66
Debt extinguished					27
Loss on debt extinguishment					$ 5
Disposal Group, Held-for-sale or Disposed of by Sale, Not Discontinued Operations \| Other
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale								$ 12	$ 15
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	866
East/West 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]
Generation capacity (in MW) \| MW		4,850
Consideration		$ 760
Working capital adjustments		137
Proceeds from sale of, net of working capital adjustments	$ 623	623
Gain (loss) on sale of business		$ 210
West/Services/Other \| Held-for-sale \| Home Solar
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment loss to adjust the carrying amount of assets and liabilities						$ 29	$ 29

Acquisitions, Discontinued Operations and Dispositions - Discontinued Operations (Details) $ in Millions		12 Months Ended
	Feb. 06, 2018 USD ($) extension	Dec. 31, 2021 USD ($) MW	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Feb. 04, 2019 USD ($) MW	Aug. 31, 2018 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generation capacity (in MW) \| MW		18,000
Income from discontinued operations, net of income tax		$ 0	$ 0	$ 321
GenOn
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income from discontinued operations, net of income tax				(3)
Discontinued Operations \| South Central Portfolio
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration					$ 1,000
Generation capacity (in MW) \| MW					1,177
Income from discontinued operations, net of income tax				28
Discontinued Operations \| NRG Yield Inc. And Zephyr Renewables
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
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]
Consideration	$ 385
Other commitment		$ 23	$ 23
Membership percentage	100.00%
Lease and easement agreement, number of extensions \| extension	2
Renewal term	10 years
Income from discontinued operations, net of income tax				$ 296

Acquisitions, Discontinued Operations and Dispositions - Summary of Results (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income/(loss) from discontinued operations, net of tax	$ 0	$ 0	$ 321
Discontinued Operations \| South Central Portfolio
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue			31
Operating costs and expenses			(23)
(Loss)/gain from operations of discontinued components, before tax			8
Income/(loss) on disposal of discontinued operations, net of tax			20
Income/(loss) from discontinued operations, net of tax			28
Discontinued Operations \| Carlsbad Energy Holdings LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue			19
Operating costs and expenses			(9)
Other expenses			(5)
Gain/(loss) from discontinued operations, net of tax			5
Gain/(loss) on disposal of discontinued operations, net of tax			265
Income/(expense) from California property tax indemnification			22
Income/(expense) from other commitments, indemnification and fees			4
Income/(loss) on disposal of discontinued operations, net of tax			291
Income/(loss) from discontinued operations, net of tax			$ 296

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, 2021	Dec. 31, 2020
Liabilities
Long-term debt	$ 8,100	$ 8,855
Carrying Amount
Liabilities
Long-term debt	8,040	8,781
Fair Value
Liabilities
Long-term debt	$ 8,327	$ 9,446

- Definition

Amount, after unamortized (discount) premium and debt issuance costs, of long-term debt. Includes, but not limited to, notes payable, bonds payable, debentures, mortgage loans and commercial paper. Excludes capital lease obligations.

+ References + Details

Fair Value of Financial Instruments - Assets and Liabilities Measured and Recorded at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	$ 32	$ 25
Other trust fund investments (classified within other non-current assets):
Other trust fund investments	1	1
Measured using net asset value practical expedient:
Total assets	8,188	1,745
Derivative liabilities:
Total liabilities	4,799	884
Foreign exchange contract
Derivative assets:
Derivative Assets	1
Derivative liabilities:
Commodity contracts	1
Commodity contracts
Derivative assets:
Derivative Assets	7,139	821
Derivative liabilities:
Commodity contracts	4,798	884
Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	33	23
U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	112	70
Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	100	89
Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	44	36
Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	122	144
Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	494	434
Measured using net asset value practical expedient:
Equity contracts	7	8
Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	4	7
Equity securities-nuclear trust fund investments
Measured using net asset value practical expedient:
Equity contracts	99	87
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)	15	10
Other trust fund investments (classified within other non-current assets):
Other trust fund investments	1	1
Measured using net asset value practical expedient:
Total assets	1,635	597
Derivative liabilities:
Total liabilities	626	86
Level 1 \| Foreign exchange contract
Derivative assets:
Derivative Assets	0
Derivative liabilities:
Commodity contracts	0
Level 1 \| Commodity contracts
Derivative assets:
Derivative Assets	981	59
Derivative liabilities:
Commodity contracts	626	86
Level 1 \| Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	33	23
Level 1 \| U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	111	69
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	494	434
Measured using net asset value practical expedient:
Equity contracts
Level 1 \| Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	1
Level 1 \| Equity securities-nuclear trust fund investments
Measured using net asset value practical expedient:
Equity contracts
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)	17	15
Other trust fund investments (classified within other non-current assets):
Other trust fund investments	0	0
Measured using net asset value practical expedient:
Total assets	5,990	914
Derivative liabilities:
Total liabilities	4,009	643
Level 2 \| Foreign exchange contract
Derivative assets:
Derivative Assets	1
Derivative liabilities:
Commodity contracts	1
Level 2 \| Commodity contracts
Derivative assets:
Derivative Assets	5,701	623
Derivative liabilities:
Commodity contracts	4,008	643
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	1
Level 2 \| Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	100	89
Level 2 \| Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	44	36
Level 2 \| Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	122	144
Level 2 \| Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Measured using net asset value practical expedient:
Equity contracts
Level 2 \| Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	4	6
Level 2 \| Equity securities-nuclear trust fund investments
Measured using net asset value practical expedient:
Equity contracts
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 (classified within other non-current assets):
Other trust fund investments	0	0
Measured using net asset value practical expedient:
Total assets	457	139
Derivative liabilities:
Total liabilities	164	155
Level 3 \| Foreign exchange contract
Derivative assets:
Derivative Assets	0
Derivative liabilities:
Commodity contracts	0
Level 3 \| Commodity contracts
Derivative assets:
Derivative Assets	457	139
Derivative liabilities:
Commodity contracts	164	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
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

Fair Value of Financial Instruments - Reconciliation of Level 3 Financial Instruments (Details) - Level 3 - Derivative - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ (16)	$ 38
Contracts added from Direct Energy acquisition	(15)
Total (losses) — realized/unrealized:
Total gains realized/unrealized included in earnings	145	(44)
Purchases	93	(13)
Transfers into Level 3	71	1
Transfers out of Level 3	15	2
Ending balance	293	(16)
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	$ 120	$ 9

Fair Value of Financial Instruments - Derivative Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Total derivative assets valued with prices provided by models and other valuation techniques percentage	6.00%
Total derivative liabilities valued with prices provided by models and other valuation techniques, percentage	3.00%
Change in credit reserve	$ (11)	$ 2

Fair Value of Financial Instruments - Significant Unobservable Inputs Used in Fair Value of Level 3 Positions (Details) $ in Millions	Dec. 31, 2021 USD ($) $ / MWh	Dec. 31, 2020 USD ($) $ / MWh
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Cash collateral paid in support of energy risk management activities	$ 291	$ 50
Cash collateral received in support of energy risk management activities	845	19
Commodity contracts
Assets
Derivative Assets	7,139	821
Liabilities
Derivative Liabilities	4,798	884
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Cash collateral paid in support of energy risk management activities	17	0
Cash collateral received in support of energy risk management activities	831	5
Commodity contracts \| Level 3
Assets
Derivative Assets	457	139
Liabilities
Derivative Liabilities	164	155
Commodity contracts \| Fair Value, Measurements, Recurring \| Level 3
Assets
Derivative Assets	457	139
Liabilities
Derivative Liabilities	164	155
Commodity contracts \| Fair Value, Measurements, Recurring \| Natural Gas Contract \| Level 3
Assets
Derivative Assets	16
Liabilities
Derivative Liabilities	$ 1
Commodity contracts \| Fair Value, Measurements, Recurring \| Natural Gas Contract \| Level 3 \| Low
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Forward Market Price (USD per MWh) \| $ / MWh	3
Commodity contracts \| Fair Value, Measurements, Recurring \| Natural Gas Contract \| Level 3 \| High
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Forward Market Price (USD per MWh) \| $ / MWh	40
Commodity contracts \| Fair Value, Measurements, Recurring \| Natural Gas Contract \| Level 3 \| Weighted Average
Fair Value Measurement Inputs and Valuation Techniques [Abstract
Forward Market Price (USD per MWh) \| $ / MWh	15
Commodity contracts \| Fair Value, Measurements, Recurring \| Power Contracts \| Level 3
Assets
Derivative Assets	$ 392	111
Liabilities
Derivative Liabilities	$ 121	$ 143
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	3	10
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	212	105
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	35	21
Commodity contracts \| Fair Value, Measurements, Recurring \| Financial Transmission Rights \| Level 3
Assets
Derivative Assets	$ 49	$ 28
Liabilities
Derivative Liabilities	$ 42	$ 12
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	(122)	(28)
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	43
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 Instruments - Counterparty Credit Risk (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Fair Value Meaurements and Concentration of Credit Risk
Counterparty credit exposure, excluding credit risk exposure under certain long term agreements	$ 2,200
Counterparty credit exposure, collateral held (cash and letters of credit) against positions	598
Counterparty credit exposure, net	$ 1,600
Company's exposure before collateral expected to roll off (as a percent)	87.00%
Net exposure (as a percent)	100.00%
Counterparty credit risk exposure to certain counterparties, threshold (as a percent)	10.00%
Estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements for the next 5 years	$ 1,100
Period of estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements (in years)	5 years
Provision for credit losses	$ 698	$ 108	$ 95
Designated as Hedging Instrument
Derivative Fair Value Meaurements and Concentration of Credit Risk
Counterparty nonperformance exposure	$ 403
Investment grade
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	55.00%
Non-Investment grade/Non-Rated
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	45.00%
Utilities, energy merchants, marketers and other
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	67.00%
Financial Institutions
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	33.00%

Accounting for Derivative Instruments and Hedging Activities - Narrative (Details) - Interest Rate Contract $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Derivative [Line Items]
Interest rate hedge	$ 1,600
Gain on derivative	$ 11

Accounting for Derivative Instruments and Hedging Activities - Net Notional Volume Buy/Sell of Open Derivative Transactions (Details) certificate in Millions, bbl in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) MMBTU MWh certificate T bbl	Dec. 31, 2020 USD ($) MMBTU MWh certificate T bbl
Long \| Emissions
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton) \| T	1	1
Long \| Renewables Energy Certificates
Derivative [Line Items]
Derivative, non-monetary notional amount (in shares) \| certificate	13	5
Long \| Coal
Derivative [Line Items]
Derivative, nonmonetary notional amount, mass (ton) \| T	19	2
Long \| Oil
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels) \| bbl	1	0
Long \| Power
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) \| MWh	185	57
Long \| Foreign Exchange
Derivative [Line Items]
Derivative, notional amount (usd) \| $	$ 279	$ 0
Short \| Natural Gas
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) \| MMBTU	813	286
Short \| Capacity
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure in (millions of btu) and (megawatt hours) \| MWh	0	1

Accounting for Derivative Instruments and Hedging Activities - Fair Value Within the Derivative Instrument Valuation (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Derivative Assets	$ 7,140	$ 821
Derivative Liabilities	4,799	884
Foreign exchange contracts - current
Derivative [Line Items]
Derivative Assets	0	0
Derivative Liabilities	1	0
Foreign exchange contracts - long-term
Derivative [Line Items]
Derivative Assets	1	0
Derivative Liabilities	0	0
Commodity contracts- current
Derivative [Line Items]
Derivative Assets	4,613	560
Derivative Liabilities	3,386	499
Commodity contracts- long-term
Derivative [Line Items]
Derivative Assets	2,526	261
Derivative Liabilities	$ 1,412	$ 385

Accounting for Derivative Instruments and Hedging Activities - Offsetting of Derivatives by Counterparty Master Agreement level and Collateral Received (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Cash Collateral (Held)/Posted	$ (845)	$ (19)
Cash Collateral (Held)/Posted	291	50
Gross Amounts of Recognized Assets / Liabilities	2,341
Derivative Instruments	0
Cash Collateral (Held) / Posted	(814)
Net Amount	1,527
Foreign exchange contract
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative Assets	1
Derivative Instruments	(1)
Cash Collateral (Held)/Posted	0
Net Amount	0
Derivative liabilities	(1)
Derivative Instruments	1
Cash Collateral (Held)/Posted	0
Net Amount	0
Gross Amounts of Recognized Assets / Liabilities	0
Derivative Instruments	0
Cash Collateral (Held) / Posted	0
Net Amount	0
Commodity contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative Assets	7,139	821
Derivative Instruments	(4,440)	(658)
Cash Collateral (Held)/Posted	(831)	(5)
Net Amount	1,868	158
Derivative liabilities	(4,798)	(884)
Derivative Instruments	4,440	658
Cash Collateral (Held)/Posted	17	0
Net Amount	(341)	(226)
Gross Amounts of Recognized Assets / Liabilities	2,341	(63)
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	(814)	(5)
Net Amount	$ 1,527	$ (68)

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Unrealized Mark To Market Results [Abstract]
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$ (41)	$ (55)	$ (68)
Reversal of acquired loss positions related to economic hedges	256	4	6
Net unrealized gains/(losses) on open positions related to economic hedges	2,501	(68)	42
Total unrealized mark-to-market gains/(losses) for economic hedging activities	2,716	(119)	(20)
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity	(18)	(20)	(11)
Reversal of Acquired (gain) Positions Related to Trading Activity	(1)	0	0
Net unrealized (losses)/gains on open positions related to trading activity	(13)	15	31
Total unrealized mark-to-market (losses)/gains for trading activity	(32)	(5)	20
Total unrealized gains/(losses)	2,684	(124)	0
Credit Risk Related Contingent Features [Abstract]
Collateral required contracts with credit rating contingent features in a net liability position	70
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	1,000
Commodity contracts
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	2,684	(124)	0
Commodity contracts \| Operating revenue
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	(196)	90	53
Commodity contracts \| Cost of operations
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	2,880	(214)	(53)
Interest rate contracts
Unrealized Mark To Market Results [Abstract]
Total unrealized gains/(losses)	$ 0	$ 0	$ (38)

Nuclear Decommissioning Trust Fund - Summary of Aggregate Fair Values and Realized Gains and Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Nuclear decommissioning trust fund disclosure
Fair Value	$ 1,008	$ 890
Unrealized Gains	471	398
Unrealized Losses	2	0
Cash and cash equivalents
Nuclear decommissioning trust fund disclosure
Fair Value	33	23
Unrealized Gains	0	0
Unrealized Losses	0	0
U.S. government and federal agency obligations
Nuclear decommissioning trust fund disclosure
Fair Value	112	70
Unrealized Gains	5	6
Unrealized Losses	$ 1	$ 0
Weighted- average maturities (in years)	10 years	10 years
Federal agency mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 100	$ 89
Unrealized Gains	2	4
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	25 years	24 years
Commercial mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 44	$ 36
Unrealized Gains	1	2
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	27 years	27 years
Corporate debt securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 122	$ 144
Unrealized Gains	7	13
Unrealized Losses	$ 1	$ 0
Weighted- average maturities (in years)	14 years	12 years
Equity securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 593	$ 521
Unrealized Gains	456	372
Unrealized Losses	0	0
Foreign government fixed income securities
Nuclear decommissioning trust fund disclosure
Fair Value	4	7
Unrealized Gains	0	1
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	13 years	10 years
South Texas Project
Nuclear decommissioning trust fund disclosure
Ownership Interest (as a percent)	44.00%

Nuclear Decommissioning Trust Fund - Summary of Proceeds from Sale of Available -for-sale Securities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Regulated Operations [Abstract]
Realized gains	$ 47	$ 34	$ 18
Realized (losses)	(9)	(13)	(9)
Proceeds from sale of securities	$ 710	$ 439	$ 381

Inventory (Details) - USD ($) $ in Millions	12 Months Ended
Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Inventory Disclosure [Abstract]
Fuel oil	$ 8	$ 37
Coal	83	73
Natural gas	206	22
Spare parts and finished goods	201	195
Total Inventory	498	327
Inventory [Line Items]
Inventory lower of cost or market adjustment	$ 0	29	$ 0
Fuel Oil
Inventory [Line Items]
Inventory lower of cost or market adjustment		$ 29

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment
Total property, plant, and equipment	$ 2,996	$ 4,483
Accumulated depreciation	(1,308)	(1,936)
Net property, plant, and equipment	1,688	2,547
Depreciation	384	295	$ 271
Facilities and equipment
Property, Plant and Equipment
Total property, plant, and equipment	$ 1,742	3,365
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	$ 271	329
Nuclear fuel
Property, Plant and Equipment
Total property, plant, and equipment	$ 222	239
Depreciable lives (in years)	5 years
Hardware and office equipment and furnishings
Property, Plant and Equipment
Total property, plant, and equipment	$ 637	453
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	$ 124	$ 97

Leases - Lease Cost and Other Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost [Abstract]
Finance lease cost	$ 4	$ 3	$ 0
Operating lease cost	91	100	109
Short-term lease cost	3	3	3
Variable lease cost	9	6	6
Sublease income	(2)	(17)	(17)
Total lease cost	105	95	101
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	102	101	104
Financing cash flows from finance leases	6	1	0
Right-of-use assets obtained in exchange for new finance lease liabilities	16	5	0
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 47	$ 4	$ 215
Finance leases:
Weighted average remaining lease term (in years)	3 years 7 months 6 days	1 year 1 month 6 days
Weighted average discount rate	2.46%	4.79%
Operating Leases [Abstract]
Weighted average remaining lease term (in years)	4 years 8 months 12 days	5 years 3 months 18 days
Weighted average discount rate	5.44%	5.63%

Leases - Annual Payments Based on the Maturities of Leases (Details) $ in Millions	Dec. 31, 2021 USD ($)
Leases [Abstract]
2022	$ 96
2023	89
2024	76
2025	52
2026	11
Thereafter	48
Total undiscounted lease payments	372
Less present value adjustment	(55)
Operating lease liability	$ 317

Asset Impairments (Details) - USD ($) $ in Millions	3 Months Ended						12 Months Ended
Asset Impairments (Details) - USD ($) $ in Millions	Dec. 31, 2021	Jun. 30, 2021	Dec. 31, 2020	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Impairments
Impairment losses							$ 35
Impairment losses, other assets									$ 12
Petra Nova Parish Holdings
Asset Impairments
Impairment losses on equity method investments					$ 18	$ 101
Letter of credit						12
Contribution in cash						95
Guarantee (up to)						$ 124
East
Asset Impairments
Impairment	$ 16
Impairment losses							35
East \| Joliet facility
Asset Impairments
Impairment	213
East \| PJM Coal Generating Assets
Asset Impairments
Impairment		$ 271
Impairment losses		$ 35
West/Services/Other
Asset Impairments
Impairment	$ 9
West/Services/Other \| Held-for-sale \| Home Solar
Asset Impairments
Impairment loss to adjust the carrying amount of assets and liabilities			$ 29	$ 29
West/Services/Other \| Cottonwood
Asset Impairments
Impairment losses on equity method investments							32
Texas
Asset Impairments
Impairment losses							$ 0
Impairment losses, other assets								$ 14

Goodwill and Other Intangibles - Changes in Goodwill (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Goodwill [Roll Forward]
Balance as of January 1, 2021	$ 579
Goodwill resulted from the acquisition of Direct Energy	1,250
Impairment losses	(35)
Foreign currency translation	1
Balance as of December 31, 2021	1,795
Texas
Goodwill [Roll Forward]
Balance as of January 1, 2021	324
Goodwill resulted from the acquisition of Direct Energy	427
Impairment losses	0
Foreign currency translation	0
Balance as of December 31, 2021	751
East
Goodwill [Roll Forward]
Balance as of January 1, 2021	240
Goodwill resulted from the acquisition of Direct Energy	648
Impairment losses	(35)
Foreign currency translation	0
Balance as of December 31, 2021	853
West/Services/Other
Goodwill [Roll Forward]
Balance as of January 1, 2021	15
Goodwill resulted from the acquisition of Direct Energy	175
Impairment losses	0
Foreign currency translation	1
Balance as of December 31, 2021	$ 191

Goodwill and Other Intangibles - Components of Intangible Assets Subject to Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	$ 2,025	$ 2,051
Purchases	348	70
Acquisition of businesses	2,352	22
Usage/Sales/Retirements	(365)	(35)
Write-off of fully amortized balances	(216)	(74)
Impairment		(14)
Other	3	5
Balance at end of period	4,147	2,025
Less accumulated amortization	(1,636)	(1,357)
Net carrying amount	2,511	668
Renewable Energy Program
Finite-lived Intangible Assets [Roll Forward]
Carrying value	123	28
Emission Allowances
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	672	662
Purchases	10	25
Acquisition of businesses	0	0
Usage/Sales/Retirements	(1)	0
Write-off of fully amortized balances	(51)	(4)
Impairment		(14)
Other	4	3
Balance at end of period	634	672
Less accumulated amortization	(536)	(563)
Net carrying amount	98	109
Customer and Supply Contracts
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	28	28
Purchases	0	0
Acquisition of businesses	610	0
Usage/Sales/Retirements	0	0
Write-off of fully amortized balances	0	0
Impairment		0
Other	0	0
Balance at end of period	638	28
Less accumulated amortization	(94)	(28)
Net carrying amount	544	0
Customer Relationships
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	527	573
Purchases	0	0
Acquisition of businesses	1,308	22
Usage/Sales/Retirements	0	0
Write-off of fully amortized balances	(158)	(70)
Impairment		0
Other	2	2
Balance at end of period	1,679	527
Less accumulated amortization	(518)	(349)
Net carrying amount	$ 1,161	$ 178
Weighted average useful life, years	12 years	5 years
Marketing Partnerships
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	$ 285	$ 285
Purchases	0	0
Acquisition of businesses	0	0
Usage/Sales/Retirements	0	0
Write-off of fully amortized balances	0	0
Impairment		0
Other	(1)	0
Balance at end of period	284	285
Less accumulated amortization	(123)	(99)
Net carrying amount	161	186
Trade Names
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	373	373
Purchases	0	0
Acquisition of businesses	310	0
Usage/Sales/Retirements	0	0
Write-off of fully amortized balances	0	0
Impairment		0
Other	0	0
Balance at end of period	683	373
Less accumulated amortization	(294)	(247)
Net carrying amount	389	126
Other
Finite-lived Intangible Assets [Roll Forward]
Balance at beginning of period	140	130
Purchases	338	45
Acquisition of businesses	124	0
Usage/Sales/Retirements	(364)	(35)
Write-off of fully amortized balances	(7)	0
Impairment		0
Other	(2)	0
Balance at end of period	229	140
Less accumulated amortization	(71)	(71)
Net carrying amount	$ 158	$ 69

Goodwill and Other Intangibles - Schedule of Amortization and Retirement of Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Total amortization	$ 495	$ 168	$ 134
Depreciation and amortization	785	435	373
Emission Allowances
Finite-Lived Intangible Assets [Line Items]
Total amortization	24	28	32
Customer and Supply Contracts
Finite-Lived Intangible Assets [Line Items]
Total amortization	66	12	14
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total amortization	327	74	44
Marketing Partnerships
Finite-Lived Intangible Assets [Line Items]
Total amortization	24	24	15
Trade Names
Finite-Lived Intangible Assets [Line Items]
Total amortization	47	27	25
Other
Finite-Lived Intangible Assets [Line Items]
Total amortization	7	3	4
Depreciation and amortization	$ 3	$ 3	$ 4

Goodwill and Other Intangibles - Schedule of Estimated Amortization of Intangible Asset for the Next Five Years (Details) $ in Millions	Dec. 31, 2021 USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2022	$ 495
2023	421
2024	297
2025	229
2026	206
Emission Allowances
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2022	14
2023	12
2024	12
2025	11
2026	9
Customer and Supply Contracts
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2022	143
2023	120
2024	73
2025	50
2026	52
Customer Relationships
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2022	265
2023	216
2024	148
2025	110
2026	95
Marketing Partnerships
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2022	23
2023	23
2024	23
2025	22
2026	22
Trade Names
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2022	47
2023	46
2024	38
2025	32
2026	24
Other
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2022	3
2023	4
2024	3
2025	4
2026	$ 4

Goodwill and Other Intangibles - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Held-for-sale
Goodwill and Other Intangibles
Emission allowances held-for-sale	$ 15	$ 14

Long-term Debt and Finance Leases - Schedule of Long-term Debt and Finance Leases (Details) $ / shares in Units, $ in Millions		12 Months Ended
	Jan. 31, 2022 $ / shares	Dec. 31, 2021 USD ($) $ / shares	Dec. 31, 2020 USD ($) $ / shares	Aug. 24, 2021	Aug. 23, 2021	Dec. 02, 2020	May 24, 2019	Dec. 07, 2017	Aug. 02, 2016
Debt Instrument [Line Items]
Long-term debt		$ 8,100	$ 8,855
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]		Total long-term debt and finance leases	Total long-term debt and finance leases
Finance leases		$ 13	$ 4
Total long-term debt and finance lease obligations		8,113	8,859
Less current maturities		(4)	(1)
Less debt issuance costs		(83)	(93)
Discounts		(60)	(74)
Total long-term debt and finance leases		7,966	8,691
Debt Instrument, Unamortized Discount [Abstract]
Total discounts		$ (60)	(74)
Senior Notes, due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage		7.25%		7.25%
Senior Notes, due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage		6.625%		6.625%
Senior Notes, due 2032
Debt Instrument [Line Items]
Interest rate, stated percentage		3.875%			3.875%
Tax-exempt bonds
Debt Instrument [Line Items]
Long-term debt		$ 466	466
Recourse Debt \| Senior Notes, due 2026
Debt Instrument [Line Items]
Long-term debt		$ 0	1,000
Interest rate, stated percentage		7.25%
Recourse Debt \| Senior Notes, due 2027
Debt Instrument [Line Items]
Long-term debt		$ 375	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%
Recourse Debt \| Senior Notes, due 2029
Debt Instrument [Line Items]
Long-term debt		$ 500	500
Interest rate, stated percentage		3.375%				3.375%
Recourse Debt \| Senior Notes, due 2031
Debt Instrument [Line Items]
Long-term debt		$ 1,030	1,030
Interest rate, stated percentage		3.625%				3.625%
Recourse Debt \| Senior Notes, due 2032
Debt Instrument [Line Items]
Long-term debt		$ 1,100	0
Interest rate, stated percentage		3.875%
Recourse Debt \| Convertible Senior Notes Due 2048
Debt Instrument [Line Items]
Long-term debt		$ 575	575
Discounts		$ (58)	$ (72)
Interest rate, stated percentage		2.75%
Effective rate		5.34%	5.19%
Conversion price per common share (in usd per share) \| $ / shares		$ 44.89	$ 46.24
Conversion ratio		0.0222761	0.0216242
Debt Instrument, Unamortized Discount [Abstract]
Total discounts		$ (58)	$ (72)
Recourse Debt \| Convertible Senior Notes Due 2048 \| Subsequent Event
Debt Instrument [Line Items]
Conversion price per common share (in usd per share) \| $ / shares	$ 44.53
Conversion ratio	0.0224563
Debt discount amortization period	3 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%
Recourse Debt \| Senior Secured First Lien Notes, due 2025
Debt Instrument [Line Items]
Long-term debt		$ 500	500
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	900
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%
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%
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)	(2)
Debt Instrument, Unamortized Discount [Abstract]
Total discounts		$ (2)	$ (2)

Long-term Debt and Finance Leases - Annual Payments Based on the Maturities of Debt and Capital Leases (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
2022	$ 4
2023	3
2024	603
2025	502
2026	0
Thereafter	7,001
Total long-term debt and finance lease obligations	$ 8,113	$ 8,859

Long-term Debt and Finance Leases - Senior Notes Issuance and Redemptions (Details) - USD ($)				12 Months Ended
	Aug. 24, 2021	Aug. 23, 2021	Dec. 02, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Aug. 02, 2016
Debt Instrument [Line Items]
Principal Repurchased				$ 1,855,000,000
Cash Paid	$ 1,900,000,000			1,949,000,000
Loss on debt extinguishment	$ 77,000,000			(77,000,000)	$ (9,000,000)	$ (51,000,000)
Write off of deferred debt issuance cost				$ 12,000,000
Senior Notes, due 2032
Debt Instrument [Line Items]
Aggregate principal amount		$ 1,100,000,000
Interest rate, stated percentage		3.875%		3.875%
Increase in basis points if sustainability targets are not achieved		0.25%
Senior Notes, due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage	7.25%			7.25%
Principal Repurchased	$ 1,000,000,000			$ 1,000,000,000
Cash Paid				$ 1,056,000,000
Senior Notes, due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%			6.625%
Principal Repurchased	$ 355,000,000			$ 855,000,000
Cash Paid				$ 893,000,000
Recourse Debt \| Senior Notes, due 2032
Debt Instrument [Line Items]
Interest rate, stated percentage				3.875%
Recourse Debt \| Senior Notes, due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage				7.25%
Recourse Debt \| Senior Notes, due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage				6.625%			6.625%
Recourse Debt \| 3.375% Senior Notes Due 2029
Debt Instrument [Line Items]
Aggregate principal amount			$ 500,000,000
Interest rate, stated percentage			3.375%	3.375%
Recourse Debt \| Senior Notes, due 2031
Debt Instrument [Line Items]
Aggregate principal amount			$ 1,000,000,000
Interest rate, stated percentage			3.625%	3.625%
Recourse Debt \| Senior Secured First Lien Notes due 2025 to 2027
Debt Instrument [Line Items]
Aggregate principal amount			$ 1,400,000,000
Recourse Debt \| 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%
Recourse Debt \| 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%
Increase in basis points if sustainability targets are not achieved			0.25%

Long-term Debt and Finance Leases - Senior Notes Redemptions (Details) - USD ($)		12 Months Ended
	Aug. 24, 2021	Dec. 31, 2021
Debt Instrument [Line Items]
Principal Repurchased		$ 1,855,000,000
Cash Paid	$ 1,900,000,000	1,949,000,000
Accrued interest		$ 29,000,000
Senior Notes, due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage	7.25%	7.25%
Principal Repurchased	$ 1,000,000,000	$ 1,000,000,000
Cash Paid		$ 1,056,000,000
Average Early Redemption Percentage		103.625%
Senior Notes, due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%	6.625%
Principal Repurchased	$ 355,000,000	$ 855,000,000
Cash Paid		$ 893,000,000
Average Early Redemption Percentage		103.313%

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, 2021 USD ($) $ / shares	Dec. 31, 2020 USD ($) $ / shares
Debt Instrument [Line Items]
Conversion price per common share (in usd per share) \| $ / shares	$ 44.89	$ 46.24
Conversion ratio	0.0222761	0.0216242
Carrying amount of equity component \| $	$ 518	$ 503

Long-term Debt and Finance Leases - Senior Notes Outstanding with Early Redemption Features (Details)	12 Months Ended
	Dec. 31, 2021	Aug. 24, 2021	Aug. 23, 2021	Dec. 02, 2020	May 24, 2019	Dec. 07, 2017	Aug. 02, 2016
6.625% Senior Notes due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%	6.625%
Senior Notes, due 2032
Debt Instrument [Line Items]
Interest rate, stated percentage	3.875%		3.875%
Recourse Debt \| 6.625% Senior Notes due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%						6.625%
Recourse Debt \| 5.750% Senior Notes due 2028
Debt Instrument [Line Items]
Interest rate, stated percentage	5.75%					5.75%
Recourse Debt \| 5.250% Senior Notes due 2029
Debt Instrument [Line Items]
Interest rate, stated percentage	5.25%				5.25%
Recourse Debt \| 3.375% Senior Notes due 2029
Debt Instrument [Line Items]
Interest rate, stated percentage	3.375%			3.375%
Recourse Debt \| 3.625% Senior Notes due 2031
Debt Instrument [Line Items]
Interest rate, stated percentage				3.625%
Recourse Debt \| Senior Notes, due 2032
Debt Instrument [Line Items]
Interest rate, stated percentage	3.875%
Recourse Debt \| Senior Notes \| Low
Debt Instrument [Line Items]
Redemption percentage of principal	25.00%
Recourse Debt \| Senior Notes \| Maximum
Debt Instrument [Line Items]
Redemption percentage of principal	30.00%

Long-term Debt and Finance Leases -Senior Notes Redemption Period (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Aug. 24, 2021	Aug. 23, 2021	Dec. 02, 2020	May 24, 2019	Dec. 07, 2017	Aug. 02, 2016
6.625% Senior Notes due 2027
Debt Instrument [Line Items]
Average Early Redemption Percentage	103.313%
Interest rate, stated percentage	6.625%		6.625%
Senior Notes, due 2032
Debt Instrument [Line Items]
Average Early Redemption Percentage	40.00%
Interest rate, stated percentage	3.875%			3.875%
Senior Notes, due 2032 \| Redemption Period Prior to August 15 2024
Debt Instrument [Line Items]
Average Early Redemption Percentage	103.875%
Outstanding principal after redemption, percentage (at least)	50.00%
Senior Notes, due 2032 \| Redemption Period Prior to February 15 2027
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.00%
Premium percentage of principal amount of note discount factor (as percent)	1.00%
Senior Notes, due 2032 \| 2027
Debt Instrument [Line Items]
Redemption Percentage (If Sustainability Performance Target has been satisfied and confirmed by External Verifier)	101.938%
Redemption Percentage (If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)	102.188%
Senior Notes, due 2032 \| 2028
Debt Instrument [Line Items]
Redemption Percentage (If Sustainability Performance Target has been satisfied and confirmed by External Verifier)	101.292%
Redemption Percentage (If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)	101.458%
Senior Notes, due 2032 \| 2029
Debt Instrument [Line Items]
Redemption Percentage (If Sustainability Performance Target has been satisfied and confirmed by External Verifier)	100.646%
Redemption Percentage (If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)	100.729%
Senior Notes, due 2032 \| 2030 and thereafter
Debt Instrument [Line Items]
Redemption Percentage (If Sustainability Performance Target has been satisfied and confirmed by External Verifier)	100.00%
Redemption Percentage (If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)	100.00%
Recourse Debt \| 6.625% Senior Notes due 2027
Debt Instrument [Line Items]
Interest rate, stated percentage	6.625%							6.625%
Recourse Debt \| 6.625% Senior Notes due 2027 \| July 15, 2021 to July 14, 2022
Debt Instrument [Line Items]
Average Early Redemption Percentage	103.313%
Recourse Debt \| 6.625% Senior Notes due 2027 \| July 15, 2022 to July 14, 2023
Debt Instrument [Line Items]
Average Early Redemption Percentage	102.208%
Recourse Debt \| 6.625% Senior Notes due 2027 \| July 15, 2023 to July 14, 2024
Debt Instrument [Line Items]
Average Early Redemption Percentage	101.104%
Recourse Debt \| 6.625% Senior Notes due 2027 \| July 15, 2024 and thereafter
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.00%
Recourse Debt \| 5.750% Senior Notes due 2028
Debt Instrument [Line Items]
Interest rate, stated percentage	5.75%						5.75%
Recourse Debt \| 5.750% Senior Notes due 2028 \| Redemption Period Prior to January 15, 2023
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.00%
Present value of note (as percentage)	1.02875
Recourse Debt \| 5.750% Senior Notes due 2028 \| January 15, 2023 to January 14, 2024
Debt Instrument [Line Items]
Average Early Redemption Percentage	102.875%
Recourse Debt \| 5.750% Senior Notes due 2028 \| January 15, 2024 to January 14, 2025
Debt Instrument [Line Items]
Average Early Redemption Percentage	101.917%
Recourse Debt \| 5.750% Senior Notes due 2028 \| January 15, 2025 to January 14, 2026
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.958%
Recourse Debt \| 5.750% Senior Notes due 2028 \| January 15, 2026 and thereafter
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.00%
Recourse Debt \| 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%
Recourse Debt \| 5.250% Senior Notes due 2029
Debt Instrument [Line Items]
Average Early Redemption Percentage	40.00%
Interest rate, stated percentage	5.25%					5.25%
Recourse Debt \| 5.250% Senior Notes due 2029 \| Redemption Period Prior to June 15, 2022
Debt Instrument [Line Items]
Average Early Redemption Percentage	105.25%
Outstanding principal after redemption, percentage (at least)	50.00%
Recourse Debt \| 5.250% Senior Notes due 2029 \| Redemption Period Prior to June 15, 2024
Debt Instrument [Line Items]
Average Early 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
Recourse Debt \| 5.250% Senior Notes due 2029 \| June 15, 2024 to June 14, 2025
Debt Instrument [Line Items]
Average Early Redemption Percentage	102.625%
Recourse Debt \| 5.250% Senior Notes due 2029 \| June 15, 2025 to June 14, 2026
Debt Instrument [Line Items]
Average Early Redemption Percentage	101.75%
Recourse Debt \| 5.250% Senior Notes due 2029 \| June 15, 2026 to June 14, 2027
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.875%
Recourse Debt \| 5.250% Senior Notes due 2029 \| June 15, 2027 and thereafter
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.00%
Recourse Debt \| 5.250% Senior Notes due 2029 \| Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)	0.50%
Recourse Debt \| 3.375% Senior Notes Due 2029
Debt Instrument [Line Items]
Average Early Redemption Percentage	40.00%
Interest rate, stated percentage	3.375%				3.375%
Recourse Debt \| 3.375% Senior Notes Due 2029 \| Redemption Period Prior to February 15, 2024
Debt Instrument [Line Items]
Average Early 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
Recourse Debt \| 3.375% Senior Notes Due 2029 \| February 15, 2024 to February 14, 2025
Debt Instrument [Line Items]
Average Early Redemption Percentage	101.688%
Recourse Debt \| 3.375% Senior Notes Due 2029 \| February 15, 2025 to February 14, 2026
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.844%
Recourse Debt \| 3.375% Senior Notes Due 2029 \| February 15, 2026 and thereafter
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.00%
Recourse Debt \| 3.375% Senior Notes Due 2029 \| Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)	0.50%
Recourse Debt \| 3.625% Senior Notes due 2031
Debt Instrument [Line Items]
Average Early Redemption Percentage	40.00%
Interest rate, stated percentage					3.625%
Recourse Debt \| 3.625% Senior Notes due 2031 \| Redemption Period Prior to February 15, 2026
Debt Instrument [Line Items]
Average Early 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%
Recourse Debt \| 3.625% Senior Notes due 2031 \| February 15, 2026 to February 14, 2027
Debt Instrument [Line Items]
Average Early Redemption Percentage	101.813%
Present value of note (as percentage)	1.01813
Recourse Debt \| 3.625% Senior Notes due 2031 \| February 15, 2027 to February 14, 2028
Debt Instrument [Line Items]
Average Early Redemption Percentage	101.208%
Recourse Debt \| 3.625% Senior Notes due 2031 \| February 15, 2028 to February 14, 2029
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.604%
Recourse Debt \| 3.625% Senior Notes due 2031 \| February 15, 2029 and thereafter
Debt Instrument [Line Items]
Average Early Redemption Percentage	100.00%
Recourse Debt \| 3.625% Senior Notes due 2031 \| Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)	0.50%
Recourse Debt \| Convertible Senior Notes Due 2048
Debt Instrument [Line Items]
Interest rate, stated percentage	2.75%
Conversion ratio	0.0222761	0.0216242
Recourse Debt \| Senior Notes, due 2032
Debt Instrument [Line Items]
Interest rate, stated percentage	3.875%
Recourse Debt \| Senior Notes, due 2032 \| Treasury Rate
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)	0.50%

Long-term Debt and Finance Leases - Receivables Securitizations and Repurchase Facility (Details) - USD ($)	Jul. 26, 2021	Sep. 22, 2020	Feb. 09, 2022	Dec. 31, 2021	Dec. 31, 2020
Receivables Facility \| Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility	$ 800,000,000				$ 750,000,000
Increase in existing borrowing commitments	$ 50,000,000
Repurchase Facility \| Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility					$ 75,000,000
Secured Debt \| Receivables Facility
Debt Instrument [Line Items]
Revolving credit facility		$ 750,000,000
Weighted average interest rate				0.646%
Borrowings outstanding				$ 0
Secured Debt \| Receivables Facility \| Letter of Credit
Debt Instrument [Line Items]
Letter of credit				400,000,000
Secured Debt \| Repurchase Facility
Debt Instrument [Line Items]
Revolving credit facility		75,000,000		75,000,000
Borrowings outstanding				$ 0
Commitment fee		$ 0
Secured Debt \| Repurchase Facility \| Subsequent Event
Debt Instrument [Line Items]
Revolving credit facility			$ 150,000,000
Secured Debt \| Repurchase Facility \| SOFR
Debt Instrument [Line Items]
Treasury rate redemption (as percentage)		1.30%

Long-term Debt and Finance Leases -Senior Credit Facility, Credit Default Swap Facility and Bilateral letter of Credit Facilities (Details) - USD ($)		3 Months Ended	12 Months Ended
	Jan. 04, 2019	Sep. 30, 2020	Dec. 31, 2020	Dec. 31, 2021
Credit Agreement 2019 \| Letter of Credit
Debt Instrument [Line Items]
Increase in revolving commitments and letters of credit			$ 150,000,000
Revolving credit facility	$ 80,000,000
Annual facility fees, percentage	1.33%
Letter of credit				$ 222,000,000
Bilateral letter of credit facilities \| Letter of Credit
Debt Instrument [Line Items]
Revolving credit facility			475,000,000
Letter of credit				469,000,000
Bilateral letter of credit facilities \| Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility			$ 475,000,000
Line of Credit \| Credit Agreement \| Revolving Credit Facility
Debt Instrument [Line Items]
Increase in revolving commitments and letters of credit		$ 802,000,000
Revolving credit facility		$ 273,000,000
Revolving commitments available				$ 3,700,000,000

Long-term Debt and Finance Leases - Put Option Agreement for Senior Debt Issuance (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2020	Dec. 31, 2021	Dec. 11, 2020
1.841% Senior Secured First Lien Notes due 2023
Debt Instrument [Line Items]
Aggregate principal amount	$ 900
Interest rate, stated percentage	1.841%
LC Agreement
Debt Instrument [Line Items]
Revolving credit facility			$ 874
Letter of credit		$ 873
Pre-capitalized Trust Securities
Debt Instrument [Line Items]
Sale pre-capitalized trust securities	$ 900
Delaware Trust
Debt Instrument [Line Items]
Put option agreement, term	3 years
Put option agreement, semi-annual Interest rate	1.65%

Long-term Debt and Finance Leases - Tax Exempt Bonds (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 17, 2020	Mar. 11, 2020
Debt Instrument [Line Items]
Long-term debt	$ 8,100,000,000	$ 8,855,000,000
NRG Indian River Power 2020, tax exempt bonds, due 2040
Debt Instrument [Line Items]
Long-term debt	$ 57,000,000	57,000,000
Interest rate, stated percentage	1.25%		1.25%
Aggregate principal amount			$ 57,000,000
NRG Indian River Power 2020, tax exempt bonds, due 2045
Debt Instrument [Line Items]
Long-term debt	$ 190,000,000	190,000,000
Interest rate, stated percentage	1.25%		1.25%
Aggregate principal amount			$ 190,000,000
NRG Dunkirk 2020, tax exempt bonds, due 2042
Debt Instrument [Line Items]
Long-term debt	$ 59,000,000	59,000,000
Interest rate, stated percentage	1.30%			1.30%
Aggregate principal amount				$ 59,000,000
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%
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%
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%
Tax-exempt bonds
Debt Instrument [Line Items]
Long-term debt	$ 466,000,000	$ 466,000,000
5.875% Dunkirk Power LLC Tax Exempt Bonds Due 2042
Debt Instrument [Line Items]
Interest rate, stated percentage	5.875%
5.375% Indian River Power LLC Tax Exempt Bonds Due 2045
Debt Instrument [Line Items]
Interest rate, stated percentage	5.375%
6.000% Indian River Power LLC Tax Exempt Bonds Due 2040
Debt Instrument [Line Items]
Interest rate, stated percentage	6.00%

Asset Retirement Obligations (Details) $ in Millions	12 Months Ended
Asset Retirement Obligations (Details) $ in Millions	Dec. 31, 2021 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of December 31, 2020	$ 760
Revisions in estimates for current obligations	(36)
Additions	5
Spending for current obligations	(51)
Accretion	42
Balance as of December 31, 2021	720
Nuclear Decommission
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of December 31, 2020	303
Revisions in estimates for current obligations	0
Additions	0
Spending for current obligations	0
Accretion	18
Balance as of December 31, 2021	321
Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of December 31, 2020	457
Revisions in estimates for current obligations	(36)
Additions	5
Spending for current obligations	(51)
Accretion	24
Balance as of December 31, 2021	$ 399

Benefit Plans and Other Postretirement Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) benefitPlan	Dec. 31, 2020 USD ($)
Benefit Plans and Other Postretirement Benefits
Number of qualified pension plans \| benefitPlan	3
Pension Benefits
Benefit Plans and Other Postretirement Benefits
Expects to contribute to the pension plans	$ 0
Actuarial loss	$ (55)	$ 126

Benefit Plans and Other Postretirement Benefits - Net Benefit Costs and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Annual periodic pension cost
Curtailment loss			$ (8)
Pension and other post retirement benefit obligations
Curtailment loss			(32)
Pension Benefits
Annual periodic pension cost
Service cost benefits earned	$ 9	$ 10	10
Interest cost on benefit obligation	27	38	46
Expected return on plan assets	(66)	(61)	(59)
Amortization of unrecognized net loss	1	5	3
Curtailment loss	2	0	0
Net periodic benefit (credit)/cost	(27)	(8)	0
Pension and other post retirement benefit obligations
Benefit obligation at January 1	1,489	1,397
Acquired benefit obligation from Direct Energy	74	0
Service cost	9	10	10
Interest cost	27	38	46
Actuarial (gain)/loss	(55)	126
Employee and retiree contributions	0	0
Curtailment loss	0	0
Benefit payments	(93)	(82)
Foreign exchange translation	1	0
Benefit obligation at December 31	1,452	1,489	1,397
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1	1,272	1,150
Acquired fair value of plan assets from Direct Energy	64	0
Actual return on plan assets	85	193
Employee and retiree contributions	0	0
Employer contributions	7	11
Benefit payments	(93)	(82)
Foreign exchange translation	1	0
Fair value of plan assets at December 31	1,336	1,272	1,150
Funded status at December 31 — excess of obligation over assets	(116)	(217)
Other Postretirement Benefits Plan
Annual periodic pension cost
Service cost benefits earned	0	0	1
Interest cost on benefit obligation	2	3	3
Amortization of unrecognized prior service cost	(10)	(14)	(13)
Amortization of unrecognized net loss	1	1	0
Curtailment loss	1	0	0
Net periodic benefit (credit)/cost	(6)	(10)	(9)
Pension and other post retirement benefit obligations
Benefit obligation at January 1	90	93
Acquired benefit obligation from Direct Energy	19	0
Service cost	0	0	1
Interest cost	2	3	3
Actuarial (gain)/loss	0	0
Employee and retiree contributions	3	3
Curtailment loss	1	0
Benefit payments	(10)	(9)
Foreign exchange translation	0	0
Benefit obligation at December 31	105	90	93
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1	0	0
Acquired fair value of plan assets from Direct Energy		0
Actual return on plan assets	0	0
Employee and retiree contributions	3	3
Employer contributions	7	6
Benefit payments	(10)	(9)
Foreign exchange translation	0
Fair value of plan assets at December 31	0	0	$ 0
Funded status at December 31 — excess of obligation over assets	$ (105)	$ (90)

Benefit Plans and Other Postretirement Benefits - Amounts Recognized in the Balance Sheets and OCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Amounts recognized in balance sheet
Other current liabilities	$ 0	$ 0
Other non-current liabilities	116	217
Amounts recognized in accumulated OCI
Net loss	52	127
Prior service cost/(credit)	2	2
Total/Net accumulated OCI	54	129
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial gain	(72)	(6)
Amortization of net actuarial loss	(1)	(5)
Amortization of prior service cost	0	0
Effect of settlement	(2)	0
Other changes in plan assets and benefit obligations recognized in other comprehensive income	(75)	(11)
Net periodic benefit credit	(27)	(8)	$ 0
Net recognized in net periodic pension credit and OCI	(102)	(19)
Significant components of NRG's domestic pension plan
Projected benefit obligation	1,452	1,489	1,397
Accumulated benefit obligation	1,423	1,455
Fair value of plan assets	1,336	1,272	1,150
Other Postretirement Benefits Plan
Amounts recognized in balance sheet
Other current liabilities	7	5
Other non-current liabilities	98	85
Amounts recognized in accumulated OCI
Net loss	5	6
Prior service cost/(credit)	(19)	(29)
Total/Net accumulated OCI	(14)	(23)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial gain	0	0
Amortization of net actuarial loss	(1)	(1)
Amortization of prior service cost	10	14
Effect of settlement	0	0
Other changes in plan assets and benefit obligations recognized in other comprehensive income	9	13
Net periodic benefit credit	(6)	(10)	(9)
Net recognized in net periodic pension credit and OCI	3	3
Significant components of NRG's domestic pension plan
Projected benefit obligation	105	90	93
Fair value of plan assets	$ 0	$ 0	$ 0

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, 2021	Dec. 31, 2020	Dec. 31, 2019
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
Postretirement Benefit Obligation
Weighted-Average Assumptions
Year Health care cost trend rate reaches ultimate trend rate	2028	2028
Significant assumptions used to calculate NRG's benefit expense
Year Health care cost trend rate reaches ultimate trend rate	2028	2028
Postretirement Benefit Obligation \| Before age 65
Weighted-Average Assumptions
Health care trend rate	6.80%	7.20%	7.80%
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	6.80%	7.20%	7.80%
Postretirement Benefit Obligation \| Age 65 and after
Weighted-Average Assumptions
Health care trend rate	4.40%	4.50%
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	4.40%	4.50%
Net Period Benefit Cost/Credit
Weighted-Average Assumptions
Year Health care cost trend rate reaches ultimate trend rate	2028	2028	2025
Significant assumptions used to calculate NRG's benefit expense
Year Health care cost trend rate reaches ultimate trend rate	2028	2028	2025
Net Period Benefit Cost/Credit \| Before age 65
Weighted-Average Assumptions
Health care trend rate	7.00%	7.50%
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	7.00%	7.50%
Net Period Benefit Cost/Credit \| Age 65 and after
Weighted-Average Assumptions
Health care trend rate	4.40%	4.50%	4.50%
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	4.40%	4.50%	4.50%
Pension Benefits
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	$ 1,336	$ 1,272	$ 1,150
Weighted-Average Assumptions
Discount rate	2.89%	2.56%
Interest crediting rate	3.07%	3.12%
Rate of compensation increase	3.06%	3.00%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	2.55%	3.26%
Interest crediting rate	3.13%	3.66%
Expected return on plan assets	5.62%	5.93%	6.35%
Rate of compensation increase	3.06%	3.00%	3.00%
Pension Benefits \| Minimum
Significant assumptions used to calculate NRG's benefit expense
Discount rate			4.38%
Pension Benefits \| Maximum
Significant assumptions used to calculate NRG's benefit expense
Discount rate			4.20%
Pension Benefits \| Common/collective trust investment — U.S. equity
Target allocations
Target allocation of pension plan assets (as percent)	17.00%
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)	15.00%
Pension Benefits \| Common/collective trust investment — fixed income
Target allocations
Target allocation of pension plan assets (as percent)	55.00%
Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	$ 13	$ 13
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	13
Pension Benefits \| Significant Observable Inputs (Level 2)
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	740	806
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	221	284
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	69	113
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	110	151
Pension Benefits \| Significant Observable Inputs (Level 2) \| Common/collective trust investment — fixed income
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	340	258
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	753	819
Pension Benefits \| Total \| Common/collective trust investment — U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	221	284
Pension Benefits \| Total \| Common/collective trust investment — non-U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	69	113
Pension Benefits \| Total \| Common/collective trust investment — non-core assets
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	110	151
Pension Benefits \| Total \| Common/collective trust investment — fixed income
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	340	258
Pension Benefits \| Total \| Short-term investment fund
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	13	13
Pension Benefits \| Fair Value Measured at Net Asset Value Per Share
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	1,336	1,272
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	78	45
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	65	84
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	405	289
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	35
Other Postretirement Benefits Plan
Benefit Plans and Other Postretirement Benefits
Fair value of plan assets	$ 0	$ 0	$ 0
Weighted-Average Assumptions
Discount rate	2.89%	2.54%
Interest crediting rate	1.94%	1.62%
Rate of compensation increase	0.00%	0.00%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	2.81%	3.26%	4.37%
Interest crediting rate	1.62%	2.28%	0.00%
Expected return on plan assets	0.00%	0.00%	0.00%
Rate of compensation increase	0.00%	0.00%	0.00%

Benefit Plans and Other Postretirement Benefits - Expected Future Benefit Payments For the Next Five Years and Other (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 25	$ 22	22
South Texas Project
STP Defined Benefit Plans
Amount reimbursed to STPNOC towards defined benefit plans	17	8
Expected reimbursement of contribution to retirement plan obligations to STPNOC in 2014	13
Pension Benefit Payments
NRG's expected future benefit payments
2022	96
2023	94
2024	91
2025	87
2026	86
2027-2031	396
STP Defined Benefit Plans
Curtailment gain	(2)	0	0
Increase to pension liability	0	0
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(116)	(217)
Net periodic benefit credit	(27)	(8)	0
Other changes in plan assets and benefit obligations recognized in other comprehensive income	(75)	(11)
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	(50)	(99)
Net periodic benefit credit	17	7
Other changes in plan assets and benefit obligations recognized in other comprehensive income	(51)	22
Other Postretirement Benefits Plan
NRG's expected future benefit payments
2022	7
2023	7
2024	7
2025	6
2026	6
2027-2031	26
Medicare prescription drug reimbursements
2022	0
2023	0
2024	0
2025	0
2026	0
2027-2031	2
STP Defined Benefit Plans
Curtailment gain	(1)	0	0
Increase to pension liability	(1)	0
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(105)	(90)
Net periodic benefit credit	(6)	(10)	$ (9)
Other changes in plan assets and benefit obligations recognized in other comprehensive income	9	13
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	(18)	(20)
Net periodic benefit credit	(4)	(4)
Other changes in plan assets and benefit obligations recognized in other comprehensive income	$ 4	$ 5
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 Common Shares issued and Outstanding (Details) - shares	2 Months Ended	12 Months Ended				14 Months Ended
	Feb. 24, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Feb. 24, 2022
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)	423,547,174	423,057,848				423,057,848
Beginning balance, treasury shares (in shares)	(179,793,275)	(178,825,915)				(178,825,915)
Beginning balance, common shares outstanding (in shares)	243,753,899	244,231,933				244,231,933
Share repurchases (in shares)		(1,084,752)	(6,062,783)	(36,301,882)
Ending balance, common shares issued (in shares)		423,547,174	423,057,848
Ending balance, treasury shares (in shares)		(179,793,275)	(178,825,915)
Ending balance, common shares outstanding (in shares)		243,753,899	244,231,933
Equivalent shares purchased in lieu of tax withholding on equity compensation issuances
Increase (Decrease) in Stockholders' Equity (in shares)
Share repurchases (in shares)		(249,013)	(711,248)	(936,928)
Subsequent Event
Increase (Decrease) in Stockholders' Equity (in shares)
Share repurchases (in shares)	(1,889,151)
Subsequent Event \| Equivalent shares purchased in lieu of tax withholding on equity compensation issuances
Increase (Decrease) in Stockholders' Equity (in shares)
Share repurchases (in shares)	(130,674)
Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued (in shares)	423,547,174	423,057,848	421,890,790	420,288,886		423,057,848
Beginning balance, common shares outstanding (in shares)	243,753,899	244,231,933	248,996,189	283,650,039		244,231,933
Shares issued under ESPP (in shares)		117,392	131,469	46,128
Shares issued from LTIP (in shares)		489,326	1,167,058	1,601,904
Ending balance, common shares issued (in shares)		423,547,174	423,057,848	421,890,790	420,288,886
Ending balance, common shares outstanding (in shares)		243,753,899	244,231,933	248,996,189	283,650,039
Common Stock \| Subsequent Event
Increase (Decrease) in Stockholders' Equity (in shares)
Shares issued from LTIP (in shares)	288,491
Ending balance, common shares issued (in shares)	423,835,665					423,835,665
Ending balance, common shares outstanding (in shares)	242,153,239					242,153,239
Treasury Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, treasury shares (in shares)	(179,793,275)	(178,825,915)	(172,894,601)	(136,638,847)		(178,825,915)
Shares issued under ESPP (in shares)		117,392	131,469	46,128
Shares issued from LTIP (in shares)		0	0	0
Share repurchases (in shares)		(1,084,752)	(6,062,783)	(36,301,882)
Ending balance, treasury shares (in shares)		(179,793,275)	(178,825,915)	(172,894,601)	(136,638,847)
Treasury Stock \| Subsequent Event
Increase (Decrease) in Stockholders' Equity (in shares)
Shares issued from LTIP (in shares)	0
Share repurchases (in shares)	(1,889,151)
Ending balance, treasury shares (in shares)	(181,682,426)					(181,682,426)

Capital Structure - Common Stock (Details) - USD ($)			1 Months Ended	2 Months Ended	3 Months Ended			12 Months Ended				14 Months Ended
Capital Structure - Common Stock (Details) - USD ($)	Jan. 21, 2022	Jan. 21, 2021	Mar. 31, 2019	Feb. 24, 2022	Mar. 31, 2020	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Feb. 24, 2022	Feb. 27, 2020	Dec. 06, 2021
Equity, Class of Treasury Stock [Line Items]
Quarterly dividends per share (usd per share)								$ 0.325	$ 0.30	$ 0.03
Dividends paid per share (in usd per share)								$ 1.30	$ 1.20	0.12
Common stock, dividends, proposed annual amount, per share (usd per share)		$ 1.30			$ 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%
Market value on offering date percentage			95.00%
Exercise price as a percentage of fair value (as a percent)			95.00%
Treasury stock reserved for issuance under the ESPP (in shares)								2,636,199
Shares repurchased (in shares)								1,084,752	6,062,783	36,301,882
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			$ 1,000,000,000
Shares repurchased (in shares)								1,333,765	6,774,031	37,238,810
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)										1,194,000,000			56,000,000
Subsequent Event
Equity, Class of Treasury Stock [Line Items]
Dividends per common share (in usd per share)	$ 0.35
Shares repurchased (in shares)				1,889,151
Subsequent Event \| Capital Allocation Plan
Equity, Class of Treasury Stock [Line Items]
Shares repurchased (in shares)												2,019,825
Scenario, Plan
Equity, Class of Treasury Stock [Line Items]
Common stock, annual dividends increase, percentage		8.00%
Scenario, Plan \| Subsequent Event
Equity, Class of Treasury Stock [Line Items]
Common stock, dividends, proposed annual amount, per share (usd per share)	$ 1.40
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)								14,372,743

Capital Structure - Summary of Changes in Shares Repurchased (Details) - USD ($)	2 Months Ended	12 Months Ended			14 Months Ended
	Feb. 24, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Feb. 24, 2022
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)		1,084,752	6,062,783	36,301,882
Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	1,889,151
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)				$ 400,000,000
Other repurchases
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)		1,084,752	6,062,783	26,863,211
Accrued stock repurchases		$ 5,000,000		$ 4,000,000
Amounts paid for shares and share equivalents purchased (in millions)		$ 44,000,000	$ 197,000,000	$ 1,008,000,000
Other repurchases \| Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	1,889,151
Amounts paid for shares and share equivalents purchased (in millions)	$ 76,000,000
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)		249,013	711,248	936,928
Average price paid per share (in shares)		$ 37.50	$ 38.23	$ 38.78
Amounts paid for shares and share equivalents purchased (in millions)		$ 9,000,000	$ 27,000,000	$ 36,000,000
Equivalent shares purchased in lieu of tax withholding on equity compensation issuances \| Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	130,674
Average price paid per share (in shares)	$ 43.08
Amounts paid for shares and share equivalents purchased (in millions)	$ 6,000,000
Capital Allocation Plan
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)		1,333,765	6,774,031	37,238,810
Average price paid per share (in shares)		$ 40.22	$ 33.05	$ 38.79
Amounts paid for shares and share equivalents purchased (in millions)		$ 53,000,000	$ 224,000,000	$ 1,444,000,000
Capital Allocation Plan \| Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)					2,019,825
Average price paid per share (in shares)					$ 40.26
Amounts paid for shares and share equivalents purchased (in millions)					$ 82,000,000

Investments Accounted for by the Equity Method and Variable Interest Entities - Summary of Equity Method Investments (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Investments Accounted for by the Equity Method
Equity investments in affiliates	$ 157	$ 346
Difference between carrying value and underlying net assets	116
Undistributed earnings from equity investment	$ 33	$ 30
Gladstone
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	37.50%
Equity investments in affiliates	$ 127
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	$ 4
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%
Petra Nova Parish Holdings \| Other Noncurrent Liabilities
Investments Accounted for by the Equity Method
Equity investments in affiliates	$ (16)

Investments Accounted for by the Equity Method and Variable Interest Entities - Variable Interest Entities and Other Equity Investments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) project MW	Dec. 31, 2020 USD ($)
Schedule of Equity Method Investments [Line Items]
Generation capacity (in MW) \| MW	18,000
Equity investments in affiliates \| $	$ 157	$ 346
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
Equity investments in affiliates \| $	$ 4
Gladstone
Schedule of Equity Method Investments [Line Items]
Ownership percentage	37.50%
Generation capacity (in MW) \| MW	1,613
Equity investments in affiliates \| $	$ 127

Investments Accounted for by the Equity Method and Variable Interest Entities - Summarized Financial Information (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Accounts receivable	$ 3,245	$ 904
Total Assets	23,182	14,902
Current liabilities	7,915	1,915
Variable Interest Entity, Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Accounts receivable	939	647
Other current assets	0	2
Total Assets	939	649
Current liabilities	78	78
Net assets	$ 861	$ 571

- Definition

Sum of the carrying amounts as of the balance sheet date of all assets that are recognized. Assets are probable future economic benefits obtained or controlled by an entity as a result of past transactions or events.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 210
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-03(11))
-URI http://asc.fasb.org/extlink&oid=120398452&loc=d3e534808-122878

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 852
-SubTopic 10
-Section 55
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=84165509&loc=d3e56426-112766

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(A))
-URI http://asc.fasb.org/extlink&oid=124359900&loc=SL124442552-122756

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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-Paragraph 22
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Income Per Share - Reconciliation of Basic and Diluted EPS (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Basic income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. common stockholders	$ 2,187	$ 510	$ 4,438
Weighted average number of common shares outstanding — basic (in shares)	245,000,000	245,000,000	262,000,000
Diluted income per share attributable to NRG Energy, Inc;	$ 8.93	$ 2.08	$ 16.94
Diluted income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. common stockholders	$ 2,187	$ 510	$ 4,438
Weighted average number of common shares outstanding — basic (in shares)	245,000,000	245,000,000	262,000,000
Incremental shares attributable to the issuance of equity compensation (treasury stock method) (in shares)	0	1,000,000	2,000,000
Weighted average number of common shares outstanding- dilutive (in shares)	245,000,000	246,000,000	264,000,000
Income per weighted average common share — diluted (in usd per share)	$ 8.93	$ 2.07	$ 16.81

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+ Details

- Definition

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

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+ Details

Segment Reporting (Details) - USD ($) $ in Millions		12 Months Ended
Segment Reporting (Details) - USD ($) $ in Millions	Aug. 24, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jan. 05, 2021
Income Statement
Revenues		$ 26,989	$ 9,093	$ 9,821
Operating expenses		22,566	7,481	8,160
Depreciation and amortization		785	435	373
Impairment losses		544	75	5
Total operating cost and expenses		23,895	7,991	8,538
Gain on sale of assets		247	3	7
Operating income		3,341	1,105	1,290
Equity in (losses)/earnings of unconsolidated affiliates		17	17	2
Impairment losses on investments		0	(18)	(108)
Other income, net		63	67	66
Loss on debt extinguishment	$ 77	(77)	(9)	(51)
Interest expense		(485)	(401)	(413)
Income from Continuing Operations Before Income Taxes		2,859	761	786
Income tax expense/(benefit)		672	251	(3,334)
Income from Continuing Operations		2,187	510	4,120
Income from discontinued operations, net of income tax		0	0	321
Net Income		2,187	510	4,441
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests		0	0	3
Net Income Attributable to NRG Energy, Inc.		2,187	510	4,438
Balance sheet
Equity investments in affiliates		157	346
Capital expenditures		269	230
Goodwill		1,795	579
Total assets		23,182	14,902
Corporate
Income Statement
Revenues		0	0	0
Operating expenses		141	57	50
Depreciation and amortization		28	34	31
Impairment losses		0	0	0
Total operating cost and expenses		169	91	81
Gain on sale of assets		211	5	6
Operating income		42	(86)	(75)
Equity in (losses)/earnings of unconsolidated affiliates		0	0	0
Impairment losses on investments			0	(5)
Other income, net		59	41	30
Loss on debt extinguishment		(77)	0	(48)
Interest expense		(469)	(384)	(385)
Income from Continuing Operations Before Income Taxes		(445)	(429)	(483)
Income tax expense/(benefit)		653	250	(3,337)
Income from Continuing Operations				2,854
Income from discontinued operations, net of income tax				321
Net Income				3,175
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests				0
Net Income Attributable to NRG Energy, Inc.		(1,098)	(679)	3,175
Balance sheet
Equity investments in affiliates		0	0
Capital expenditures		45	25
Goodwill		0	0
Total assets		19,081	11,152
Eliminations
Income Statement
Revenues		10	(4)	(7)
Operating expenses		10	(4)	(7)
Depreciation and amortization		0	0	0
Impairment losses		0	0	0
Total operating cost and expenses		10	(4)	(7)
Gain on sale of assets		0	0	0
Operating income		0	0	0
Equity in (losses)/earnings of unconsolidated affiliates		0	0	0
Impairment losses on investments			0	0
Other income, net		(14)	0	0
Loss on debt extinguishment		0	0	0
Interest expense		14	0	0
Income from Continuing Operations Before Income Taxes		0	0	0
Income tax expense/(benefit)		0	0	0
Income from Continuing Operations				0
Income from discontinued operations, net of income tax				0
Net Income				0
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests				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		(26,653)	(7,360)
Texas
Balance sheet
Goodwill		751	324		$ 427
Texas \| Operating Segments
Income Statement
Revenues		10,293	6,309	7,069
Operating expenses		8,692	5,249	5,821
Depreciation and amortization		331	227	188
Impairment losses		0	14	1
Total operating cost and expenses		9,023	5,490	6,010
Gain on sale of assets		19	0	0
Operating income		1,289	819	1,059
Equity in (losses)/earnings of unconsolidated affiliates		(3)	(12)	(4)
Impairment losses on investments			(18)	(103)
Other income, net		8	11	20
Loss on debt extinguishment		0	0	0
Interest expense		(1)	0	0
Income from Continuing Operations Before Income Taxes		1,293	800	972
Income tax expense/(benefit)		0	0	0
Income from Continuing Operations				972
Income from discontinued operations, net of income tax				0
Net Income				972
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests				0
Net Income Attributable to NRG Energy, Inc.		1,293	800	972
Balance sheet
Equity investments in affiliates		0	(13)
Capital expenditures		153	130
Goodwill		751	324
Total assets		12,265	7,641
Texas \| Eliminations
Income Statement
Revenues		(5)	(6)	(1)
East
Balance sheet
Goodwill		853	240		$ 648
East \| Operating Segments
Income Statement
Revenues		13,033	2,258	2,262
Operating expenses		10,257	1,758	1,843
Depreciation and amortization		338	138	117
Impairment losses		535	0	0
Total operating cost and expenses		11,130	1,896	1,960
Gain on sale of assets		0	0	1
Operating income		1,903	362	303
Equity in (losses)/earnings of unconsolidated affiliates		0	0	0
Impairment losses on investments			0	0
Other income, net		7	7	6
Loss on debt extinguishment		0	(4)	0
Interest expense		(1)	(14)	(18)
Income from Continuing Operations Before Income Taxes		1,909	351	291
Income tax expense/(benefit)		0	(1)	2
Income from Continuing Operations				289
Income from discontinued operations, net of income tax				0
Net Income				289
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests				0
Net Income Attributable to NRG Energy, Inc.		1,909	352	289
Balance sheet
Equity investments in affiliates		0	0
Capital expenditures		50	45
Goodwill		853	240
Total assets		13,673	1,790
East \| Eliminations
Income Statement
Revenues		18	6	(8)
West/Services/Other
Balance sheet
Goodwill		191	15
West/Services/Other \| Operating Segments
Income Statement
Revenues		3,653	530	497
Operating expenses		3,466	421	453
Depreciation and amortization		88	36	37
Impairment losses		9	61	4
Total operating cost and expenses		3,563	518	494
Gain on sale of assets		17	(2)	0
Operating income		107	10	3
Equity in (losses)/earnings of unconsolidated affiliates		20	29	6
Impairment losses on investments			0	0
Other income, net		3	8	10
Loss on debt extinguishment		0	(5)	(3)
Interest expense		(28)	(3)	(10)
Income from Continuing Operations Before Income Taxes		102	39	6
Income tax expense/(benefit)		19	2	1
Income from Continuing Operations				5
Income from discontinued operations, net of income tax				0
Net Income				5
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests				3
Net Income Attributable to NRG Energy, Inc.		83	37	2
Balance sheet
Equity investments in affiliates		157	359
Capital expenditures		21	30
Goodwill		191	15
Total assets		4,816	1,679
West/Services/Other \| Eliminations
Income Statement
Revenues		$ (3)	$ (4)	$ 2

Income Taxes - Income Tax Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current
State	$ 48	$ 22	$ 2
Foreign	3	4	4
Total — current	51	26	6
Deferred
U.S. Federal	569	168	(3,000)
State	36	60	(340)
Foreign	16	(3)	0
Total — deferred	621	225	(3,340)
Total income tax expense/(benefit)	672	251	(3,334)
Domestic and foreign components of income from continuing operations before income tax expense
U.S.	2,759	749	771
Foreign	100	12	15
Income from Continuing Operations Before Income Taxes	2,859	761	786
Reconciliation of the U.S. federal statutory rate to NRG's effective rate from continuing operations
Income from continuing operations before income taxes	2,859	761	786
Tax at federal statutory tax rate	600	160	165
Foreign operations	(3)	0	0
State taxes	111	18	13
Permanent differences	8	8	(9)
Changes in valuation allowance	(29)	24	(3,492)
Deferred impact of state tax rate changes	(10)	2	12
Recognition of uncertain tax benefits	(10)	3	(10)
Return to provision adjustments	5	36	0
Other	0	0	(13)
Total income tax expense/(benefit)	$ 672	$ 251	$ (3,334)
Effective income tax rate (as a percent)	23.50%	33.00%	(424.20%)

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves	$ 114	$ 79
Difference between book and tax basis of property	436	357
Pension and other postretirement benefits	65	86
Equity compensation	7	10
Bad debt reserve	168	16
Derivatives, net	0	11
U.S. Federal net operating loss carryforwards	1,773	2,117
Foreign net operating loss carryforwards	112	102
State net operating loss carryforwards	328	351
Federal and state tax credit carryforwards	384	384
Federal benefit on state uncertain tax positions	3	4
Interest disallowance carryforward per §163(j) of the Tax Act	6	4
Inventory obsolescence	9	6
Other	15	10
Total deferred tax assets	3,420	3,537
Deferred tax liabilities:
Emissions allowances	20	21
Derivatives, net	591	0
Goodwill	40	29
Intangibles amortization (excluding goodwill)	363	2
Equity method investments	62	156
Convertible Debt	14	16
Total deferred tax liabilities	1,090	224
Total deferred tax assets less deferred tax liabilities	2,330	3,313
Valuation allowance	(248)	(266)
Net deferred tax asset	2,082	3,047
NRG's net deferred tax position
Deferred tax asset	2,155	3,066
Deferred tax liability	(73)	(19)
Net deferred tax asset	$ 2,082	$ 3,047

Income Taxes -Narrative for Deferred Tax Assets and Valuation Allowance, Taxes Receivable and Payable (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Taxes receivable and payable
Valuation allowance - current period activities	$ 29	$ (24)	$ 3,492
NOLs utilized			$ 593
Deferred tax asset	2,082	3,047
Net deferred tax asset (before valuation)	2,300	3,300
Valuation allowance	248	$ 266
Federal Tax Authority
Taxes receivable and payable
Operating loss carryforwards	1,800
Current net federal tax receivable	16
State and Local Jurisdiction
Taxes receivable and payable
Operating loss carryforwards	328
Current taxes payable	13
Foreign Tax Authority
Taxes receivable and payable
Operating loss carryforwards	112
Current taxes receivable	$ 11

Income Taxes - Reconciliation of Uncertain Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Uncertain tax benefits
Uncertain tax benefits	$ 13	$ 15
Liability for uncertainty in income taxes, noncurrent	14	18
Unrecognized tax benefits, income tax penalties expense	1
Accrued interest and penalties related to unrecognized tax benefits	1	3
Uncertain tax benefits reconciliation
Balance as of January 1	15	15
Increase due to current year positions	4	3
Increase due to acquired balance from Direct Energy	9	0
Settlements, payments and statute closure	(15)	(3)
Uncertain tax benefits as of December 31	$ 13	$ 15

Stock-Based Compensation - Long-Term Incentive Plan (Details) - shares	Apr. 27, 2017	Dec. 31, 2021	Dec. 31, 2020
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)		8,871,874	9,385,730
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)		20,131	78,903

Stock-Based Compensation - Restricted Stock Units (RSUs (Details) - RSUs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Stock-Based Compensation
Award vesting period	3 years
Units
Non-vested at beginning of period (in shares)	519,514
Granted (in shares)	479,415
Forfeited (in shares)	(49,816)
Vested (in shares)	(279,161)
Non-vested at end of period (in shares)	669,952	519,514
Weighted Average Grant Date Fair Value per Unit
Non-vested at beginning of period (in usd per share)	$ 35.87
Granted (in usd per share)	39.00	$ 38.05	$ 37.37
Forfeited (in usd per share)	37.41
Vested (in usd per share)	34.18
Non-vested at end of period (in usd per share)	$ 38.69	$ 35.87
Vested in period, fair value	$ 12	$ 17	$ 36
Weighted average grant date fair value (in usd per share)	$ 39.00	$ 38.05	$ 37.37

Stock-Based Compensation - Deferred Stock Units, DSUs (Details) - DSUs - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Units
Balance outstanding at the beginning of the period (in shares)	342,706
Granted (in shares)	64,512
Converted to Common Stock (in shares)	(23,090)
Balance outstanding at the end of the period (in shares)	384,128	342,706
Weighted Average Grant Date Fair Value per Unit
Balance outstanding at the beginning of the period, (in usd per share)	$ 25.37
Granted (in usd per share)	32.27	$ 35.59	$ 34.84
Vested (in usd per share)	30.92
Balance outstanding at the end of the period (in usd per share)	$ 26.11	$ 25.37
Aggregate intrinsic value for DSUs outstanding	$ 17,000,000	$ 13,000,000	$ 13,000,000
Aggregate intrinsic values for DSUs converted to common stock during the period	$ 1,000,000	$ 2,000,000	$ 2,000,000
Weighted average grant date fair value (in usd per share)	$ 32.27	$ 35.59	$ 34.84

Stock -Based Compensation - Performance Stock Units, RPSUs Plan description (Details) - RPSUs	12 Months Ended
	Dec. 31, 2021
Stock-Based Compensation
Award vesting period	3 years
Share-based Payment Arrangement, Tranche One
Stock-Based Compensation
Award vesting right, percentage	0.00%
Share-based Payment Arrangement, Tranche Two
Stock-Based Compensation
Award vesting right, percentage	25.00%
Share-based Payment Arrangement, Tranche Three
Stock-Based Compensation
Award vesting right, percentage	100.00%
Share-based Payment Arrangement, Tranche Four
Stock-Based Compensation
Award vesting right, percentage	15.00%
Share-based Payment Arrangement, Tranche Five
Stock-Based Compensation
Award vesting right, percentage	200.00%

Stock-Based Compensation - Performance Stock Units (Details) - $ / shares	1 Months Ended	12 Months Ended
	Sep. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
PSUs
Units
Non-vested at beginning of period (in shares)		793,561
Granted (in shares)		426,768
Forfeited (in shares)		(93,031)
Vested (in shares)		(396,793)
Non-vested at end of period (in shares)		730,505	793,561
Weighted Average Grant-Date Fair Value per Unit
Non-vested at beginning of period (in usd per share)		$ 41.69
Granted (in usd per share)		46.78	$ 23.75	$ 22.50
Forfeited (in usd per share)		47.21
Vested (in usd per share)		35.32
Non-vested at end of period (in usd per share)		$ 47.40	$ 41.69
RPSUs
Units
Granted (in shares)	60,815
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected volatility	37.38%	34.05%	30.15%	40.72%
Expected term (in years)		3 years	3 years	3 years
Risk free rate	0.42%	0.17%	1.58%	2.45%

Stock-Based Compensation - Non-Qualified Stock Options (Details) - NQSOs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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)	77,047
Forfeited (in shares)	(4,800)
Exercised (in shares)	(54,377)
Outstanding at the end of the period (in shares)	17,870	77,047
Exercisable at the end of the period (in shares)	17,870
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding (in usd per share)	$ 25.13
Forfeited (in usd per share)	29.08
Exercised (in usd per share)	26.44
Outstanding (in usd per share)	20.07	$ 25.13
Exercisable (in usd per share)	$ 20.07
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures
Weighted Average Remaining Contractual Term, Outstanding (in years)	2 months 12 days	6 months
Weighted Average Remaining Contractual Term, Exercisable (in years)	2 months 12 days
Aggregate Intrinsic Value	$ 0	$ 1
Aggregate Intrinsic Value, Exercisable	$ 0

Stock-Based Compensation - Intrinsic Value of Options Exercised and Cash Received (Details) - NQSOs - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total intrinsic value of options exercised	$ 1	$ 1	$ 2
Cash received from options exercised	$ 1	$ 1	$ 3

Stock-Based Compensation - Supplemental Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Stock-Based Compensation
Minimum tax withholdings	$ 9	$ 27	$ 36
Compensation Expense	27	27	32
Tax detriment/(benefit) recognized	2	(9)	(12)
Unrecognized Total Cost	41
RSUs
Stock-Based Compensation
Compensation Expense	9	9	9
Unrecognized Total Cost	$ 16
Weighted Average Recognition Period Remaining (In years)	1 year 9 months 18 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
RPSUs
Stock-Based Compensation
Compensation Expense	$ 9	10	10
Unrecognized Total Cost	$ 15
Weighted Average Recognition Period Remaining (In years)	1 year 2 months 8 days
Award vesting period	3 years
PRSUs
Stock-Based Compensation
Compensation Expense	$ 7	$ 6	$ 11
Unrecognized Total Cost	$ 10
Weighted Average Recognition Period Remaining (In years)	1 year 6 months 7 days
Award vesting period	3 years

Related Party Transactions - Summary of Material Related Party Transactions With Third Party Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	$ 49	$ 52	$ 44
Gladstone
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	4	4	4
Ivanpah
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	39	43	35
Midway-Sunset
Related Party Transaction [Line Items]
Revenues from Related Parties Included in Operating Revenues	$ 6	$ 5	$ 5

- Definition

Amount of revenue, fees and commissions earned from transactions between (a) a parent company and its subsidiaries; (b) subsidiaries of a common parent; (c) an entity and trusts for the benefit of employees, for example, but not limited to, pension and profit-sharing trusts that are managed by or under the trusteeship of the entity's management; (d) an entity and its principal, owners, management, or members of their immediate families; and (e) affiliates.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iv))
-URI http://asc.fasb.org/extlink&oid=124359900&loc=SL124442552-122756

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 946
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.6-07.1(c))
-URI http://asc.fasb.org/extlink&oid=120401555&loc=SL114874292-224272

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iii)(B))
-URI http://asc.fasb.org/extlink&oid=124359900&loc=SL124442526-122756

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(C))
-URI http://asc.fasb.org/extlink&oid=124359900&loc=SL124442552-122756

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(5))
-URI http://asc.fasb.org/extlink&oid=124359900&loc=SL124442526-122756

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(5))
-URI http://asc.fasb.org/extlink&oid=124359900&loc=SL124442552-122756

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iv))
-URI http://asc.fasb.org/extlink&oid=124359900&loc=SL124442526-122756

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.1(e))
-URI http://asc.fasb.org/extlink&oid=123367319&loc=SL114868664-224227

+ Details

Commitments and Contingencies - Certain Fuel, Transportation and Purchased Energy Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Coal, Gas and Transportation Commitments
Commitments and Contingencies
Purchases under coal, gas and transportation arrangement	$ 600	$ 500	$ 600
Minimum purchase commitment
2022	122
2023	54
2024	63
2025	62
2026	51
Thereafter	26
Total	378
Purchases under power contracts	600	500	600
Renewable Purchased Power Agreements
Commitments and Contingencies
Purchases under coal, gas and transportation arrangement	12,800	1,800	2,600
Minimum purchase commitment
2022	1,566
2023	1,036
2024	617
2025	382
2026	289
Thereafter	1,071
Total	4,961
Purchases under power contracts	$ 12,800	$ 1,800	$ 2,600

Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) assessment	Oct. 31, 2021 facility	Jun. 30, 2019 facility	Apr. 30, 2019 case	Feb. 28, 2019 case
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
Insurance coverage, waiting period	56 days
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
Number of facilities \| facility		2
Sierra Club Et Al V. Midwest Generation L L C
Loss Contingencies [Line Items]
Number of facilities \| facility			4
Direct Energy vs. Stanley, Forte, Schafer and Lane
Loss Contingencies [Line Items]
Number of class action lawsuits \| case				3
Direct Energy vs. Burk and Dickson 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

Environmental Matters (Details) $ in Millions	Dec. 31, 2021 USD ($)	Oct. 31, 2021 facility
Environmental Remediation Obligations [Abstract]
Environmental proceedings, disclosure threshold \| $	$ 1
Number of facilities \| facility		2

Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
Cash Flow Information (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Interest paid, net of amount capitalized	$ 433	$ 340	$ 372
Income taxes paid, net of refunds	32	24	8
(Decreases)/additions to fixed assets for accrued capital expenditures	$ (16)	$ (6)	$ 1

Guarantees - Schedule of Maximum Potential Exposure (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Guarantor Obligations
Under 1 Year	$ 4,333
1-3 Years	56
3-5 Years	24
Over 5 Years	189
Guarantees by Remaining Maturity, Total	4,602	$ 1,746
Letters of credit and surety bonds
Guarantor Obligations
Under 1 Year	4,064
1-3 Years	31
3-5 Years	0
Over 5 Years	0
Guarantees by Remaining Maturity, Total	4,095	1,153
Asset sales guarantee obligations
Guarantor Obligations
Under 1 Year	269
1-3 Years	25
3-5 Years	24
Over 5 Years	96
Guarantees by Remaining Maturity, Total	414	506
Other guarantees
Guarantor Obligations
Under 1 Year	0
1-3 Years	0
3-5 Years	0
Over 5 Years	93
Guarantees by Remaining Maturity, Total	$ 93	$ 87

Guarantees - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
Guarantees - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Guarantor Obligations
Guarantee obligation	$ 4,602	$ 1,746
Letters of credit and surety bonds
Guarantor Obligations
Guarantee obligation	$ 4,095	1,153
Letters of credit and surety bonds, maximum expiration period (in years)	1 year
Asset sales guarantee obligations
Guarantor Obligations
Guarantee obligation	$ 414	$ 506
California property tax indemnity	$ 158

Jointly Owned Plants (Details) $ in Millions	Dec. 31, 2021 USD ($)
South Texas Project Units 1 and 2, Bay City, TX
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	44.00%
Property, Plant & Equipment	$ 421
Accumulated Depreciation	(208)
Construction in Progress	$ 4
Cedar Bayou Unit 4, Baytown, TX
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	50.00%
Property, Plant & Equipment	$ 220
Accumulated Depreciation	(109)
Construction in Progress	$ 12

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Allowance for doubtful accounts, deducted from accounts receivable
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	$ 67	$ 43	$ 32
Charged to Costs and Expenses	698	108	95
Charged to Other Accounts	112	0	0
Deductions	(194)	(84)	(84)
Balance at End of Period	683	67	43
Income tax valuation allowance, deducted from deferred tax assets
Income tax valuation allowance, deducted from deferred tax assets
Balance at Beginning of Period	266	242	3,794
Charged to Costs and Expenses	(29)	24	(3,543)
Charged to Other Accounts	11	0	(9)
Deductions	0	0	0
Balance at End of Period	$ 248	$ 266	$ 242