0001013871-21-000005 | 10-K | XBRL Viewer

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

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

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

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

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500,000,000	500,000,000
Common stock, shares issued (in shares)	423,057,848	421,890,790
Common stock, shares outstanding (in shares)	244,231,933	248,996,189
Treasury stock, shares (in shares)	178,825,915	172,894,601

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

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

Total

Cumulative Effect, Period of Adoption, Adjustment

NRG Yield, Inc.

Common Stock

Additional Paid-In Capital

NRG Yield, Inc.

Accumulated Deficit

Cumulative Effect, Period of Adoption, Adjustment

Treasury Stock

Accumulated Other Comprehensive Loss

Noncon- trolling Interest

NRG Yield, Inc.

Increase (Decrease) in Stockholders' Equity

Adoption of new accounting standards

$ 1,968

$ 15

$ 4

$ 8,376

$ (6,268)

$ 15

$ (2,386)

$ (72)

$ 2,314

Beginning balance at Dec. 31, 2017

1,968

8,376

(6,268)

(2,386)

(72)

2,314

Increase (Decrease) in Stockholders' Equity

Net loss (income)

294

268

Other comprehensive loss

(22)

Sale of assets to NRG Yield, Inc

$ 16

$ 8

Shares reissuance for ESPP

(2)

Share repurchases

(1,250)

Equity-based awards activity, net

Issuance of common stock

Common stock dividends

^[1]

(37)

Distributions to noncontrolling interest and dividends paid

(43)

$ (61)

(43)

$ (61)

Contributions from noncontrolling interests

304

Adoption of new accounting standards

(1,234)

$ 15

8,510

(6,022)

$ 15

(3,632)

(94)

Sale of NRG Yield and other business

(2,548)

Equity component of convertible senior notes

101

Ending balance at Dec. 31, 2018

(1,234)

8,510

(6,022)

(3,632)

(94)

Increase (Decrease) in Stockholders' Equity

Adoption of new accounting standards

(1,234)

8,510

(6,022)

(3,632)

(94)

Net loss (income)

4,438

Other comprehensive loss

(98)

Shares reissuance for ESPP

Share repurchases

(1,409)

Equity-based awards activity, net

(16)

Issuance of common stock

Common stock dividends

^[1]

(32)

Adoption of new accounting standards

(1,234)

8,501

(1,616)

(5,039)

(192)

Ending balance at Dec. 31, 2019

1,658

8,501

(1,616)

(5,039)

(192)

Increase (Decrease) in Stockholders' Equity

Adoption of new accounting standards

1,658

8,501

(1,616)

(5,039)

(192)

Net loss (income)

510

Other comprehensive loss

(14)

Shares reissuance for ESPP

Share repurchases

(197)

Equity-based awards activity, net

(3)

Issuance of common stock

Common stock dividends

^[1]

(297)

Adoption of new accounting standards

1,658

8,517

(1,403)

(5,232)

(206)

Repurchase of partners' equity interest in VIE

Ending balance at Dec. 31, 2020

1,680

8,517

(1,403)

(5,232)

(206)

Increase (Decrease) in Stockholders' Equity

Adoption of new accounting standards

$ 1,680

$ 4

$ 8,517

$ (1,403)

$ (5,232)

$ (206)

$ 0

[1]	Dividends per common share were $1.20 for the year ended December 31, 2020 and $0.12 for each of the years ended December 31, 2019 and 2018

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

Nature of Business	12 Months Ended
Nature of Business	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of Business General NRG Energy, Inc., or NRG or the Company, is an integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to customers by producing and selling energy and related products and services in major competitive power and gas markets in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. NRG is a customer-centric business focused on perfecting the integrated model by balancing retail load with generation supply within its deregulated markets. As of December 31, 2020, the Company sold energy, services, and innovative, sustainable products and services directly to retail customers under the names NRG, Reliant, Green Mountain Energy, Stream and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation. NRG also conducts business under the brand name of Direct Energy as a result of the Company's acquisition of Direct Energy, a North American subsidiary of Centrica plc, on January 5, 2021. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. Following the acquisition, the Company serves more than 6 million customers. In addition, Direct Energy is a participant in the wholesale gas and power markets in the United States and Canada. Note 4, Acquisitions, Discontinued Operations and Dispositions for further discussion of the acquisition of Direct Energy. The Company began managing its integrated model based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of 2020. The Company's updated segment structure reflects how management makes financial decisions and allocates resources. The Company's businesses are segregated as follows: •Texas, which includes all activity related to customer, plant and market operations in Texas; •East, which includes the remaining activity related to customer operations and all activity related to plant and market operations in the East; •West/Other, which includes the following assets and activities: (i) all activity related to plant and market operations in the West, (ii) activity related to the Cottonwood power plant that was sold to Cleco on February 4, 2019 and is being leased back until 2025, (iii) the remaining renewables activity, including the Company’s equity method investments in Ivanpah Master Holdings, LLC and Agua Caliente (which was sold on February 3, 2021), the remaining Home Solar assets (which were primarily sold on November 13, 2020) and the NFL stadium solar generating assets, and (iv) activity related to the Company’s equity method investment for the Gladstone power plant in Australia; and •Corporate activities. All affected disclosures presented herein have been recast to reflect these changes for all periods presented. For further discussion of segment reporting, refer to Note 20, Segment Reporting. The acquired operations of Direct Energy will be integrated into the existing NRG segment structure. Domestic customer and market operations will be combined into the corresponding geographical segments of Texas, East and West/Other. The East segment will also include the deregulated customer and market operations of Canada. The West/Other segment will also include activity related to the regulated operations in Alberta, Canada and the services businesses. COVID-19 In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the COVID-19 outbreak a national emergency. Electricity was deemed a 'critical and essential business operation' under various state and federal governmental COVID-19 mandates. NRG had activated its Crisis Management Team ("CMT") in January 2020 to proactively manage the Company's response to the impacts of COVID-19. NRG continues to remain focused on protecting the health and well-being of its employees, while supporting its customers and the communities in which it operates and assuring the continuity of its operations. In June 2020, summer-critical office employees returned to the offices and safety protocols were successfully implemented. The Company continues to maintain certain restrictions on business travel and face-to-face sales channels, remote work practices remain in place and there are enhanced cleaning and hygiene protocols in all of its facilities. In addition, select essential employees and contractors are continuing to report to plant and certain office locations. The Company also continues to require pre-entry screening, including temperature checks, separation of work crews, additional personal protective equipment for employees and contractors when social distancing cannot be maintained, and a ban on all non-essential visitors. The Company has not experienced any material disruptions in its ability to continue its business operations to date. The first COVID-19 vaccine became available in the United States in December 2020. NRG continues to advocate alongside state and federal trade groups for the high prioritization of essential electric industry personnel for inoculation against COVID-19. States are receiving weekly doses of vaccines and allocating those doses to frontline healthcare workers, elderly populations and high risk individuals. NRG continues to monitor state information, as well as dosage and allocation numbers to anticipate the latest timing of vaccine distribution to our essential employees. The Company will continue to evaluate additional return to normal work operations on a location-by-location basis as COVID-19 conditions evolve. Discontinued Operations On December 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company concluded that the sale of its South Central Portfolio to Cleco, excluding the Cottonwood facility, met held-for-sale criteria and should be presented as a discontinued operation, as the sale represented a strategic shift in the business in which NRG operates. The financial information for all historical periods was recast in 2018 to reflect the presentation of these entities as discontinued operations. On August 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company deconsolidated NRG Yield, Inc. and its Renewables Platform for financial reporting purposes. The financial information for all historical periods was recast in 2018 to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations. As a result of the sale of NRG Yield, the Company no longer controls the Agua Caliente project. Due to this change in control, the Company deconsolidated the Agua Caliente project from its financial results and began accounting for the project as an equity method investment.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

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.

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

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

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


	Year Ended December 31,
(In millions)	2020		2019		2018
Income from continuing operations, net of income tax	$	510	$	4,117	$	465
Income/(loss) from discontinued operations, net of income tax	—		321		(197)
Net income attributable to NRG Energy, Inc. stockholders	$	510	$	4,438	$	268

Cash and Cash Equivalents

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

Funds Deposited by Counterparties

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if

any collateral will be held for more than twelve 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.

Credit Losses

On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, or ASU No. 2016-13, using the modified retrospective approach. Following the adoption of the new standard, the Company’s process of estimating expected credit losses remains materially consistent with its historical practice. Information prior to January 1, 2020, which was previously referred to as the allowance and provision for bad debt, has not been restated and continues to be reported under the accounting standards in effect for that period.

Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues an allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and industrial customers. The Company writes off customer contract receivable balances against the allowance for credit losses when it is determined a receivable is uncollectible.

The following table represents the activity in the allowance for credit losses for the year ended December 31, 2020:


(In millions)	Year Ended December 31, 2020
Beginning balance	$	43
Provision for credit losses	108
Write-offs	(101)
Recoveries collected	17
Ending balance	$	67

Restricted Cash

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


	Year Ended December 31,
(In millions)	2020		2019		2018
Cash and cash equivalents	$	3,905	$	345	$	563
Funds deposited by counterparties	19		32		33
Restricted cash	6		8		17
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows	$	3,930	$	385	$	613

Restricted cash consists primarily of funds held within the Company's projects that are restricted in their use.

Inventory

Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at weighted average cost. The Company removes these inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the fuel oil, coal, raw materials, and spare parts costs in the ordinary course of business. Finished goods inventory is valued at the lower of cost or net realizable value with cost being determined on a first-in first-out basis. The Company removes these inventories as they are sold to customers. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however, impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation, other than nuclear fuel, is computed using the straight-line method, while nuclear fuel is amortized based on units

of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.

Asset Impairments

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is indicated if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the consolidated statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets, and present value techniques.

Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is an other-than-temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value. For further discussion of these matters, refer to Note 11, Asset Impairments.

Development Costs and Capitalized Interest

Development costs include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized interest and capitalized project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.

Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2020, 2019 and 2018, was $2 million, $3 million and $7 million, respectively.

Debt Issuance Costs

Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt, or as an asset if the issuance costs relate to revolving debt agreements or certain other financing arrangements.

Intangible Assets

Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis. As of December 31, 2020 and 2019, the Company had accumulated amortization related to its intangible assets of $1.4 billion and $1.3 billion, respectively.

Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.

Goodwill

In accordance with ASC 350, Intangibles-Goodwill and Other, or ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable.

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

In the absence of sufficient qualitative factors indicating that it is more-likely-than-not that no impairment occurred, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing the fair value to its book value. If the fair value of the reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, the Company recognizes an impairment loss equal to the difference between book value and fair value.

For further discussion of goodwill and goodwill impairment losses recognized refer to Note 12, Goodwill and Other Intangibles.

Income Taxes

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

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

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

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

The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using income tax rates that are expected to be in effect when the deferred tax is realized.

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

In accordance with ASC 805 and as discussed further in Note 21, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax (benefit)/expense.

Contract Amortization

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

Lease Revenue

Certain of the Company’s revenues are obtained through leases of rooftop residential solar systems, which are accounted for as operating leases in accordance with ASC 842, Leases. Pursuant to the lease agreements, the customers’ monthly payments are pre-determined fixed monthly amounts and may include an annual fixed percentage escalation to reflect the impact of utility rate increases over the lease term, which is 20 years. The Company records operating lease revenue on a straight-line basis over the life of the lease term. Certain customers made initial down payments that are being amortized over the life of the lease. The difference between the payments received and the revenue recognized is recorded as deferred revenue.

Lessor Accounting

Certain of the Company's revenues are obtained through PPAs or other contractual agreements. Many of these agreements are accounted for as operating leases under ASC 842.

Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or finance lease. Contingent rental income under ASC 840 was $104 million for the year ended December 31, 2018.

Gross Receipts and Sales Taxes

In connection with its retail sales, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2020, 2019 and 2018, the Company's revenues and cost of operations included gross receipts taxes of $107 million, $109 million and $99 million,

respectively. Additionally, the Company records sales taxes collected from its taxable retail customers and remitted to the various governmental entities on a net basis; thus, there is no impact on the Company's consolidated statement of operations.

Purchased Energy and Other Cost of Sales for Customer Operations

The cost of energy for electricity sales and services to retail customers is included in cost of operations and is based on actual and estimated supply volumes for the applicable reporting period. A portion of the cost of energy, $98 million, $103 million and $105 million as of December 31, 2020, 2019 and 2018, respectively, was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.

Derivative Financial Instruments

The Company accounts for derivative financial instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as cash flow hedges, if elected for hedge accounting, are deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings.

The Company's primary derivative instruments are power purchase or sales contracts, fuels purchase contracts, and other energy related commodities used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, the Company assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such a contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. In this case, the gain or loss previously deferred in accumulated OCI would be frozen until the underlying hedged instrument is delivered unless the transactions being hedged are no longer probable of occurring in which case the amount in OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until the underlying hedged item is delivered. The Company had no cash flow hedges as of December 31, 2020.

Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.

NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

Foreign Currency Translation and Transaction Gains and Losses

The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's consolidated statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's consolidated statements of operations. For the years ended December 31, 2020, 2019 and 2018, amounts recognized as foreign currency transaction gains/(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2020, 2019 and 2018 were $(2) million, $(13) million and $(13) million, respectively.

Concentrations of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the

terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 5, Fair Value of Financial Instruments, for a further discussion of derivative concentrations.

Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payable, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 5, Fair Value of Financial Instruments, for a further discussion of fair value of financial instruments.

Asset Retirement Obligations

The Company accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.

Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 15, Asset Retirement Obligations, for a further discussion of AROs.

Pensions and Other Postretirement Benefits

The Company offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits, or ASC 715. The Company recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of the Company's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. The Company's actuarial consultants assist in determining assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.

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

Stock-Based Compensation

The Company accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718. The fair value of the Company's performance stock units is estimated on the date of grant using a Monte Carlo valuation model. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's deferred stock units. The fair value of the Company's restricted stock units is derived from the closing price of NRG's common stock at the grant date. Forfeiture rates are estimated based on an analysis of the Company's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award.

Investments Accounted for by the Equity Method

The Company has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents the Company from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates. Distributions from equity method investments that represent earnings on the Company's investment are included within cash flows from operating activities and distributions from equity method investments that represent a return of the Company's investment are included within cash flows from investing activities.

Tax Equity Arrangements

The Company’s redeemable noncontrolling interest in subsidiaries represented third-party interests in the net assets under certain tax equity arrangements, which were consolidated by the Company, that had been entered into to finance the cost of solar energy systems under operating leases. The Company determined that the provisions in the contractual agreements of

these structures represented substantive profit sharing arrangements. Further, the Company had determined that the appropriate methodology for calculating the redeemable noncontrolling interest that reflected the substantive profit sharing arrangements was a balance sheet approach that utilized the HLBV method. Under the HLBV method, the amounts reported as redeemable noncontrolling interests represented the amounts the investors that were party to the tax equity arrangements would hypothetically receive at each balance sheet date under the liquidation provisions of the contractual agreements, assuming the net assets of the funding structures were liquidated at their recorded amounts. The investors’ interests in the results of operations of the funding structures were determined as redeemable noncontrolling interests at the start and end of each reporting period, after taking into account any capital transactions between the structures and the funds’ investors. The calculations utilized to apply the HLBV method included estimated calculations of taxable income or losses for each reporting period. During the first quarter of 2020, the Company repurchased its partners' equity interest as further described in Note 18, Investments Accounted for by the Equity Method and Variable Interest Entities. The Company has no remaining tax equity arrangements as of December 31, 2020.

Redeemable Noncontrolling Interest

To the extent that the third-party has the right to redeem their interests for cash or other assets, the Company had included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet. During the first quarter of 2020, the Company repurchased its partners' equity interest. The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2020, 2019 and 2018.


	(In millions)
Balance as of December 31, 2017	$	78
Distributions to redeemable noncontrolling interest	(3)
Contributions from redeemable noncontrolling interest	26
Non-cash adjustments to redeemable noncontrolling interest	(8)
Net income attributable to redeemable noncontrolling interest - continuing operations	1
Net loss attributable to redeemable noncontrolling interest - discontinued operations	(27)
Sale of NRG Yield and the Renewables Platform (a)	(48)
Balance as of December 31, 2018	19
Distributions to redeemable noncontrolling interest	(2)


Net income attributable to redeemable noncontrolling interest - continuing operations	3


Balance as of December 31, 2019	20




Repurchase of redeemable noncontrolling interest	(20)
Balance as of December 31, 2020	$	—

(a) See Note 4, Acquisitions, Discontinued Operations and Dispositions, for further information regarding the sale of NRG Yield and its Renewables Platform

Sale-Leaseback Arrangements

NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneously leases back the same asset to the Company. If the seller-lessee transfers control of the underlying assets to the buyer-lessor, the arrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as operating leases on the Company's consolidated balance sheets. See Note 10, Leases, for further discussion.

Marketing and Advertising Costs

The Company expenses its marketing and advertising costs as incurred and includes them within selling, general and administrative expenses. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Advertising expenses for the years ended December 31, 2020, 2019 and 2018 were $74 million, $66 million and $73 million, respectively.

Reorganization Costs

Reorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily reflect severance and contract modifications. There were no reorganization costs for the year ended December 31, 2020. Reorganization costs for the years ended December 31, 2019 and 2018 were $23 million and $90 million, respectively.

Business Combinations

The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination. In addition, transaction costs are expensed as incurred.

Use of Estimates

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

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

Reclassifications

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

Recent Accounting Developments - Guidance Adopted in 2020

ASU 2020-09 — In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470) - Amendments to SEC Paragraphs Pursuant to SEC Release No. 33-10762, or ASU 2020-09, to reflect the SEC’s amended disclosure rules for guaranteed debt securities offerings. The final rule amends the disclosure requirements in SEC Regulation S-X, Rule 3-10, which require entities to separately present financial statements for subsidiary issuers and guarantors of registered debt securities unless certain exceptions are met. The amended rule allows entities to provide summarized financial information of the parent company and its issuers and guarantors on a combined basis either in a note to the financial statements or as part of management’s discussion and analysis. ASU 2020-09 is effective for filings on or after January 4, 2021, with early adoption permitted. The Company adopted the amendments effective December 31, 2020. As the amendments contemplate changes in disclosures only, it did not have an impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-17 — In October 2018, the FASB issued ASU No. 2018-17, Consolidations (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities, or ASU No. 2018-17, in response to stakeholders’ observations that Topic 810, Consolidations, could be improved thereby improving general purpose financial reporting. Specifically, ASU No. 2018-17 requires application of the variable interest entity (VIE) guidance to private companies under common control and consideration of indirect interest held through related parties under common control for determining whether fees paid to decision makers and service providers are variable interests. The Company adopted the amendments effective January 1, 2020 using the retrospective approach. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-15 — In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in Cloud Computing Arrangement That Is a Service Contract, or ASU No. 2018-15. The amendments in ASU No. 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs incurred to develop or obtain internal-use software (and hosting arrangement that include an internal-use software license). The amendment also requires the customer to amortize the capitalized implementation costs of a hosting arrangement that is a service contract over the term of the hosting arrangement. The Company adopted the amendments effective January 1, 2020 using the prospective approach. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-13 — In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirement for Fair value Measurement), or ASU No. 2018-13. The amendments in ASU No. 2018-13 eliminate such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy and add new disclosure requirements for Level 3 measurements. The Company adopted the amendments

effective January 1, 2020. Certain disclosures in ASU No. 2018-13 were applied on a retrospective basis and others on a prospective basis as required. As the amendments contemplates changes in disclosures only, it did not have an impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2016-13 — In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Statements, or ASU No. 2016-13, which was further amended through various updates issued by the FASB thereafter. The guidance in ASU No. 2016-13 provides a new model for recognizing credit losses on financial assets carried at amortized cost using an estimate of expected credit losses, instead of the "incurred loss" methodology previously required for recognizing credit losses that delayed recognition until it was probable that a loss was incurred. The estimate of expected credit losses is to be based on consideration of past events, current conditions and reasonable and supportable forecasts of future conditions. The Company adopted the standard and its subsequent corresponding updates effective January 1, 2020 using the modified retrospective approach. Results for the reporting periods after January 1, 2020 are presented under Topic 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company's adoption of Topic 326 did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2020-06 — In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40), or ASU No. 2020-06. The guidance in ASU 2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock. In addition, ASU 2020-06 improves and amends the related earnings per share guidance. This standard is effective for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years. Early adoption is permitted in fiscal years beginning after December 15, 2020, including interim periods within those fiscal years. The Company is currently in the process of assessing the impact of this guidance on the consolidated financial statements and disclosures related to earnings per share.

ASU 2019-12 — In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, or ASU No. 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 does not believe that the adoption of this ASU will have a material impact on the Company's results of operations, cash flows, or statement of financial position.

Revenue Recognition

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Revenue Recognition

Revenue from Contracts with Customers

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

Retail Revenue

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

Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators, utilities, or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer

usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

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

Energy Revenue

Both physical and financial transactions consist of revenues billed to a third party at either market or negotiated contract terms to optimize the financial performance of the Company's generating facilities. Electric energy revenue is recognized upon transmission to the customer over time, using the output method for measuring progress of satisfaction of performance obligations. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. The Company applies the invoicing practical expedient in recognizing energy revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. Financial transactions used to hedge the sale of electricity are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.

Capacity Revenue

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

Performance Obligations

As of December 31, 2020, estimated future fixed fee performance obligations are $668 million, $289 million, $47 million, $36 million and $20 million for fiscal years 2021, 2022, 2023, 2024 and 2025, respectively. These performance obligations are for cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non performance.

Renewable Energy Credits

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

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

Sale of Emission Allowances

The Company records its inventory of emission allowances as part of intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of expected usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. The Company records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.

Disaggregated Revenue

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the years ended December 31, 2020, 2019 and 2018:


	For the Year Ended December 31, 2020
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue
Mass Market	$	5,027	$	1,306	$	—	$	(2)	$	6,331
Business Solutions	1,034		95		—		—		1,129
Total retail revenue	6,061		1,401		—		(2)		7,460
Energy revenue(a)	24		183		333		(1)		539
Capacity revenue(a)	—		620		61		(1)		680
Mark-to-market for economic hedging activities(b)	2		88		(3)		8		95

Other revenue(a)	222		62		43		(8)		319
Total operating revenue	6,309		2,354		434		(4)		9,093
Less: Lease revenue	—		1		17		—		18
Less: Realized and unrealized ASC 815 revenue	30		314		38		3		385

Total revenue from contracts with customers	$	6,279	$	2,039	$	379	$	(7)	$	8,690





(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	67	$	43	$	(5)	$	105
Capacity revenue	—		156		—		—		156
Other revenue	28		3		(2)		—		29
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	For the Year Ended December 31, 2019
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue
Mass Market	$	5,027	$	1,230	$	—	$	(3)	$	6,254
Business Solutions	1,205		74		—		—		1,279
Total retail revenue	6,232		1,304		—		(3)		7,533
Energy revenue(a)	529		322		318		—		1,169
Capacity revenue(a)	—		664		36		—		700
Mark-to-market for economic hedging activities(b)	47		(29)		16		(1)		33

Other revenue(a)(c)	261		58		70		(3)		386
Total operating revenue	7,069		2,319		440		(7)		9,821
Less: Lease revenue	—		1		19		—		20
Less: Realized and unrealized ASC 815 revenue	1,562		183		67		(2)		1,810

Total revenue from contracts with customers	$	5,507	$	2,135	$	354	$	(5)	$	7,991





(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Energy revenue	$	1,459	$	98	$	39	$	(1)	$	1,595
Capacity revenue	—		109		—		—		109
Other revenue	56		5		12		—		73
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	For the Year Ended December 31, 2018
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue
Mass Market	$	4,618	$	974	$	—	$	(1)	$	5,591
Business Solutions	1,238		65		—		—		1,303
Total retail revenue	5,856		1,039		—		(1)		6,894
Energy revenue(a)	371		546		566		13		1,496
Capacity revenue(a)	—		746		79		—		825
Mark-to-market for economic hedging activities(b)	(77)		(35)		(5)		(13)		(130)

Other revenue(a)(c)	251		75		84		(17)		393
Total operating revenue	6,401		2,371		724		(18)		9,478
Less: Lease revenue	1		1		19		—		21
Less: Realized and unrealized ASC 815 revenue	1,096		210		2		1		1,309

Total revenue from contracts with customers	$	5,304	$	2,160	$	703	$	(19)	$	8,148





(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Energy revenue	$	1,131	$	90	$	(2)	$	14	$	1,233
Capacity revenue	—		137		—		—		137
Other revenue	42		17		9		1		69
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

Contract Balances

The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31, 2020 and 2019:


(In millions)	December 31, 2020		December 31, 2019
Deferred customer acquisition costs	$	113	$	133

Accounts receivable, net - Contracts with customers	866		1,002
Accounts receivable, net - Derivative instruments	33		18
Accounts receivable, net - Affiliate	5		5
Total accounts receivable, net	$	904	$	1,025

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	393	$	402

Deferred revenues (a)	$	60	$	82

(a) Deferred revenues from contracts with customers for the years ended December 31, 2020 and 2019 were approximately $31 million and $24 million, respectively.

The revenue recognized from contracts with customers during both years ended December 31, 2020 and 2019 relating to the deferred revenue balance at the beginning of each period was $13 million. The change in deferred revenue balances during the years ended December 31, 2020 and 2019 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.

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

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

- 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=121604090&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=121604090&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=121604090&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=121604090&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=121604090&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=121604090&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=121604090&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=121604090&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=121604090&loc=SL49130554-203045

+ Details

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

12 Months Ended

Dec. 31, 2020

Discontinued Operations and Disposal Groups [Abstract]

Acquisitions, Discontinued Operations and Dispositions

Acquisitions

Direct Energy Acquisition

On January 5, 2021 (the "Acquisition Closing Date"), the Company acquired all of the issued and outstanding common shares of Direct Energy, a North American subsidiary of Centrica plc. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition increased NRG's retail portfolio by over 3 million customers and strengthens its integrated model. It also broadens the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business.

The Company paid an aggregate purchase price of $3.625 billion in cash, subject to a purchase price adjustment of $77 million. The Company funded the purchase price using a combination of $715 million of cash on hand, $166 million from a draw on its Revolving Credit Facility (of which $107 million was used to fund acquisition costs and financing fees that are not included in the aggregate purchase price above) as well as approximately $2.9 billion in secured and unsecured corporate debt issued in December 2020. The Company also increased its collective collateral facilities by $3.4 billion as of the Acquisition Closing Date to meet the additional liquidity requirements related to the acquisition, as detailed in the following table:


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

(a) Available upon the Acquisition Closing Date

For further discussion see Note 13, Receivables Securitization and Repurchase Facility and Note 14, Long-term Debt and Finance Leases.

Acquisition costs of $17 million for the year ended December 31, 2020 are included in selling, general and administrative costs in the Company's consolidated statement of operations.

The acquisition will be recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair value of certain net assets acquired and the amount of goodwill to be recognized are still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.

The purchase price is provisionally allocated as follows:


	(In millions)
Assets
Cash and cash equivalents	$	152
Current assets	3,374
Property, plant and equipment	166
Goodwill and other intangibles (a)	3,446
Other non-current assets	687
Total assets acquired	7,825

Liabilities
Current liabilities	3,085
Non-current liabilities	1,038
Total liabilities assumed	4,123
Direct Energy Purchase Price	$	3,702

(a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of Direct Energy with NRG's existing businesses.

Midwest Generation Lease Purchase — On September 29, 2020, Midwest Generation acquired all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $260 million. The purchase was funded with cash-on-hand. Upon closing, lease expense related to these facilities, which totaled approximately $14 million in 2019, and the operating lease liability of $148 million were eliminated.

Stream Energy Acquisition — On August 1, 2019, the Company completed the acquisition of Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $329 million, including working capital and other adjustments of approximately $29 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers. The purchase price was allocated as follows:


	(In millions)
Account receivable	$	98
Accounts payable	(73)
Other net current and non-current working capital	5
Marketing partnership	154
Customer relationships	85
Trade name	28
Other intangible assets	26
Goodwill (a)	6
Stream Purchase Price	$	329

(a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of Stream Energy with NRG's existing businesses. Goodwill of $5 million and $1 million was assigned to the Texas and East segments, respectively, and is not deductible for tax purposes

XOOM Energy Acquisition — On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada, for approximately $213 million, including working capital and other adjustments of $48 million. The acquisition increased NRG's retail portfolio by approximately 395,000 RCEs or 300,000 customers. The purchase price was allocated as follows:


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

(a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of XOOM Energy with NRG's existing businesses. Goodwill of $28 million and $6 million was assigned to the Texas and East segments, respectively, and is deductible for tax purposes

Small Book Acquisitions — In 2020, the Company acquired multiple books of customers totaling approximately 56,000 customers for $22 million. During 2019, the Company acquired several books of customers totaling approximately 72,000 customers for $17 million, of which $13 million was paid in 2019. During 2018, the Company acquired several books of customers totaling approximately 115,000 customers, along with brand names, for $44 million, of which $40 million was paid in 2018 and $2 million was paid in 2019. The majority of the purchase price for the 2020, 2019 and 2018 book acquisitions were allocated to acquired intangible assets.

Discontinued Operations

Sale of South Central Portfolio

On February 4, 2019, the Company completed the sale of its South Central Portfolio to Cleco for cash consideration of $1 billion excluding working capital and other adjustments. The Company concluded that the divested business met the criteria for discontinued operations, as the disposition represents a strategic shift in the business in which NRG operates and held-for-sale criteria as of December 31, 2018. As such, all prior period results for the operations of the South Central Portfolio were reclassified as discontinued operations at December 31, 2018. In connection with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested business, which have been substantially completed in 2020.

The South Central Portfolio includes the 1,153 MW Cottonwood natural gas generating facility. Upon the closing of the sale of the South Central Portfolio, NRG entered into a lease agreement with Cleco to leaseback the Cottonwood facility through 2025. Due to its continuing involvement with the Cottonwood facility, NRG did not use held-for-sale or discontinued operations treatment in accounting for the Cottonwood facility.

Summarized results of South Central discontinued operations were as follows:


	Year Ended December 31,
(In millions)	2019		2018
Operating revenues	$	31	$	410
Operating costs and expenses	(23)		(346)
Other income	—		2


Gain from operations of discontinued components	8		66
Gain on disposal of discontinued operations, net of tax	20		—
Gain from discontinued operations, including disposal, net of tax	$	28	$	66

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

On August 31, 2018, the Company completed the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform to GIP for total cash consideration of $1.348 billion. The Company concluded that the divested businesses met the criteria for discontinued operations, as the dispositions represented a strategic shift in the business in which NRG operates. As such, all prior period results for the transaction were reclassified as discontinued operations. In connection with the transaction, NRG entered into a transition services agreement to provide certain corporate services to the divested businesses in 2018, which concluded in 2020. During the year ended December 31, 2019, the Company recorded an adjustment to reduce the purchase price by $15 million in connection with the completion of the Patriot Wind project. During the year ended December 31, 2019, the Company reduced the liability related to the indemnification of NRG Yield for any increase in property taxes for certain solar properties by $22 million due to updated estimates.

Carlsbad

On February 6, 2018, NRG entered into an agreement with NRG Yield and GIP to sell 100% of its membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, for $385 million of cash consideration, excluding working capital adjustments. The primary condition to close the Carlsbad transaction was the completion of the sale of NRG Yield and the Renewables Platform. At the time of the sale of NRG Yield and the Renewables Platform in August 2018, the Company concluded that the Carlsbad project met the criteria for discontinued operations and accordingly, all current and prior period results for Carlsbad were reclassified as discontinued operations. The transaction closed on February 27, 2019. Carlsbad will continue to have a ground lease and easement agreement with NRG with an initial term ending in 2039 and two ten-year extensions. As a result of the transaction, additional commitments related to the project totaled $23 million as of December 31, 2020 and December 31, 2019.

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



(In millions)	2019		2018
Operating revenues	$	19	$	909
Operating costs and expenses	(9)		(661)

Other expenses	(5)		(174)
Gain/(loss) from operations of discontinued components, before tax	5		74
Income tax expense	—		4
Gain/(loss) from discontinued operations, net of tax	5		70
Gain/(loss) on disposal of discontinued operations, net of tax	265		(134)
Income/(expense) from California property tax indemnification	22		(153)
Income/(expense) from other commitments, indemnification and fees	4		(75)
Income/(loss) on disposal of discontinued operations, net of tax	291		(362)
Income/(loss) from discontinued operations, net of tax	$	296	$	(292)

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

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

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

GenOn

On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer controlled GenOn as it was subject to the control of the Bankruptcy Court; and, accordingly, NRG deconsolidated GenOn and its subsidiaries for financial reporting purposes as of such date.

By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn met the criteria for discontinued operations, as this represented a strategic shift in the business in which NRG operated. As such, all prior period results for GenOn were reclassified in 2017 as discontinued operations.

Summarized results of discontinued operations were as follows:


	Year Ended December 31,
(In millions)	2019		2018
Interest income - affiliate	$	—	$	3
Income/(loss) from discontinued operations, net of tax	—		3
Settlement consideration, insurance and services credit	—		63
Pension and post-retirement liability assumption	—		21
Other	(3)		(53)
(Loss)/income on disposal of discontinued operations, net of tax	(3)		31
(Loss)/income from discontinued operations, net of tax	$	(3)	$	34

GenOn Settlement and Plan Confirmation

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

GenOn's plan of reorganization was confirmed on December 14, 2018. Pursuant to the confirmed plan, NRG retained the pension liability for GenOn employees for service provided prior to the completion of the reorganization. NRG also retained the liability for GenOn's post-employment and retiree health and welfare benefits. As a result of GenOn's emergence from bankruptcy, NRG took a deduction for GenOn tax losses of $9.5 billion, including a worthless stock deduction.

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

REMA Plan of Reorganization

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

GenMA Settlement

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

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

•NRG provided $38 million in letters of credit as new qualifying credit support to GenOn Mid-Atlantic; such letters of credit were never drawn and were returned and canceled on December 17, 2019 and

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

Dispositions

On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MWs of fossil generating assets from its East and West regions of operations for total proceeds of $760 million, subject to standard purchase price adjustments and certain other indemnifications. As part of the transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill plant in New York City through April 2025. The transaction is expected to close in the fourth quarter of 2021, and is subject to various closing conditions, approvals and consents, including FERC, NYSPSC, and antitrust review under Hart-Scott-Rodino.

On November 19, 2020, the Company entered an agreement to sell its 35% ownership in Agua Caliente to Clearway Energy for $202 million. The sale of the solar project closed on February 3, 2021.

In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $29 million, as further discussed in Note 11, Asset Impairments. On November 13, 2020, the Company completed the sale of the Home Solar business for cash proceeds of $66 million, resulting in a $2 million loss on the sale. In connection with the sale, the Company extinguished debt of $27 million and recognized a $5 million loss on the extinguishment.

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

On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for cash proceeds of approximately $16 million and recorded a gain of $17 million. Prior to the sale, Canal 3 entered into a financing arrangement and received cash proceeds of $167 million, of which $151 million was distributed to the Company. The related debt was non-recourse to NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3. The Company entered into a project management agreement in 2018 to manage construction of Canal 3 and substantial completion was reached in June 2019.

The Company completed other asset sales for cash proceeds of $15 million and $22 million during the years ended December 31, 2020 and 2019, respectively.

Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2020

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

The estimated carrying values and fair values of the Company's recorded financial instruments not carried at fair market value are as follows:


	As of December 31,
	2020				2019
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets
Notes receivable	$	2	$	2	$	11	$	8
Liabilities
Long-term debt, including current portion (a)	$	8,781	$	9,446	$	5,956	$	6,504

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

The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt, and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of December 31, 2020 and 2019:


	As of December 31, 2020				As of December 31, 2019
(In millions)	Level 2		Level 3		Level 2		Level 3
Long-term debt, including current portion	$	9,446	$	—	$	6,388	$	116

Fair Value Accounting under ASC 820

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

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

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

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

Recurring Fair Value Measurements

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

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


	As of December 31, 2020
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	25	$	10	$	15	$	—

Nuclear trust fund investments:
Cash and cash equivalents	23		23		—		—
U.S. government and federal agency obligations	70		69		1		—
Federal agency mortgage-backed securities	89		—		89		—
Commercial mortgage-backed securities	36		—		36		—
Corporate debt securities	144		—		144		—
Equity securities	434		434		—		—
Foreign government fixed income securities	7		1		6		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	821		59		623		139


Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	87		—		—		—
Equity securities	8		—		—		—
Total assets	$	1,745	$	597	$	914	$	139
Derivative liabilities:
Commodity contracts	$	884	$	86	$	643	$	155

Total liabilities	$	884	$	86	$	643	$	155


	As of December 31, 2019
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current or non-current assets)	$	20	$	—	$	20	$	—
Nuclear trust fund investments:
Cash and cash equivalents	17		17		—		—
U.S. government and federal agency obligations	68		68		—		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	29		—		29		—
Corporate debt securities	109		—		109		—
Equity securities	388		388		—		—
Foreign government fixed income securities	5		—		5		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,170		84		893		193


Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments	78		—		—		—
Equity securities	8		—		—		—
Total assets	$	1,993	$	558	$	1,156	$	193
Derivative liabilities:
Commodity contracts	$	1,103	$	143	$	805	$	155

Total liabilities	$	1,103	$	143	$	805	$	155

The following tables reconcile, for the years ended December 31, 2020 and 2019, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:


	For the Year Ended December 31, 2020
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
(In millions)	Derivatives (a)
Beginning balance as of January 1, 2020	$	38


Total (losses) — realized/unrealized included in earnings	(44)


Purchases	(13)

Transfers into Level 3 (b)	1
Transfers out of Level 3 (b)	2
Ending balance as of December 31, 2020	$	(16)
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2020	$	9

(a)Consists of derivatives assets and liabilities, net

(b)Transfers into/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers into/out of Level 3 are from/to Level 2


	For the Year Ended December 31, 2019
	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
(In millions)	Debt Securities		Derivatives (a)		Total
Beginning balance as of January 1, 2019	$	19	$	20	$	39
Contracts added from acquisitions	—		(3)		$	(3)

Total (losses) — realized/unrealized included in earnings	—		(26)		(26)


Purchases	—		40		40

Sale	(19)		—		(19)
Transfers into Level 3 (b)	—		2		2
Transfers out of Level 3 (b)	—		5		5
Ending balance as of December 31, 2019	$	—	$	38	$	38
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2019	$	—	$	17	$	17

(a)Consists of derivatives assets and liabilities, net

(b)Transfers into/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers into/out of Level 3 are from/to Level 2

Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations.

Non-derivative fair value measurements

NRG's investments in debt securities are classified as Level 3 and consist of non-traded debt instruments that were valued based on third-party market value assessments.

The trust fund investments are held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, U.S. government and federal agency obligations are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of corporate debt securities are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Certain equity securities, classified as commingled funds, are analogous to mutual funds, are maintained by investment companies, and hold certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities classified as commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are measured using net asset value practical expedient. See also Note 7, Nuclear Decommissioning Trust Fund.

Derivative fair value measurements

A portion of the Company's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 17% of derivative assets and 18% of derivative liabilities. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk, which for interest rate swaps is calculated utilizing the bilateral method based on published default probabilities. For commodities, to the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. For interest rate swaps and commodities, the credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2020 the credit reserve resulted in a $2 million increase primarily within cost of operations. As of December 31, 2019 the credit reserve did not result in a significant change in fair value in operations revenue and cost of operations.

The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2020, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

NRG's significant positions classified as Level 3 include physical and financial power executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value.

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of December 31, 2020 and 2019:


	Significant Unobservable Inputs
	December 31, 2020
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	$	111	$	143	Discounted Cash Flow	Forward Market Price (per MWh)	$	10	$	105	$	21
FTRs	28		12		Discounted Cash Flow	Auction Prices (per MWh)	(28)		43		0
	$	139	$	155


	Significant Unobservable Inputs
	December 31, 2019
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	$	151	$	139	Discounted Cash Flow	Forward Market Price (per MWh)	$	8	$	218	$	24
FTRs	42		16		Discounted Cash Flow	Auction Prices (per MWh)	(105)		213		0
	$	193	$	155

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2020 and 2019:

Significant Unobservable Input

Position

Change In Input

Impact on Fair Value Measurement

Forward Market Price Power

Buy

Increase/(Decrease)

Higher/(Lower)

Forward Market Price Power

Sell

Increase/(Decrease)

Lower/(Higher)

FTR Prices

Buy

Increase/(Decrease)

Higher/(Lower)

FTR Prices

Sell

Increase/(Decrease)

Lower/(Higher)

Under the guidance of ASC 815, entities may choose to offset cash collateral posted or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2020, the Company recorded $50 million of cash collateral posted and $19 million of cash collateral received on its balance sheet.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, the following item is a discussion of the concentration of credit risk for the Company's financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at the Company to cover the credit risk of the counterparty until positions settle.

Counterparty Credit Risk

As of December 31, 2020, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $210 million and NRG held collateral (cash and letters of credit) against those positions of $14 million, resulting in a net exposure of $204 million. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 54% of the Company's exposure before collateral is expected to roll off by the end of 2022. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.


Category	Net Exposure (a) (b) (% of Total)
Utilities, energy merchants, marketers and other	96	%
Financial institutions	4


Total	100	%


Category	Net Exposure (a) (b) (% of Total)
Investment grade	59	%
Non-Investment grade/Non-Rated	41

Total	100	%

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

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

The Company currently has $47 million exposure to two wholesale counterparties in excess of 10% of the total net exposure discussed above as of December 31, 2020. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.

RTOs and ISOs

The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and includes credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of overall market and are excluded from the above exposures.

Exchange Traded Transactions

The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk.

Long-Term Contracts

Counterparty credit exposure described above excludes credit risk exposure under certain long term contracts, primarily solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2020, aggregate credit risk exposure managed by NRG to these counterparties was approximately $645 million for the next five years.

Retail Customer Credit Risk

The Company is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. The Company manages retail credit risk through the use of established credit policies that include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of December 31, 2020, the Company's retail customer credit exposure to C&I and Mass customers was diversified across many customers and various industries, as well as government entities. The Company is also subject to risk with respect to its residential solar customers. The Company's provision for credit losses was $108 million, $95 million, and $85 million for the years ending December 31, 2020, 2019, and 2018, respectively. Current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in credit losses.

- 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, 2020

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, and interest rate swaps.

As the Company engages principally in the trading and marketing of its generation assets and retail operations, some of NRG's commercial activities qualify for NPNS accounting. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the retail supply and fuels supply contracts are recorded under mark-to-market accounting. All of NRG's hedging and trading activities are subject to limits within the Company's Risk Management Policy.

Energy-Related Commodities

To manage the commodity price risk associated with the Company's competitive supply activities and the price risk associated with wholesale power sales from the Company's electric generation facilities and retail power sales from NRG's retail operations, NRG enters into a variety of derivative and non-derivative hedging instruments, utilizing the following:

•Forward contracts, which commit NRG to purchase or sell energy commodities or purchase fuels in the future;

•Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;

•Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual, or notional, quantity;

•Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity;

•Extendable swaps, which include a combination of swaps and options executed simultaneously for different periods. This combination of instruments allows NRG to sell out-year volatility through call options in exchange for natural gas swaps with fixed prices in excess of the market price for natural gas at that time. The above-market swap combined with its later-year call option are priced in aggregate at market at the trade's inception; and

•Weather derivative products used to mitigate a portion of lost revenue due to weather.

The objectives for entering into derivative contracts designated as hedges include:

•Fixing the price of a portion of anticipated power purchases for the Company's retail sales;

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

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

These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

As of December 31, 2020, NRG's derivative assets and liabilities consisted primarily of the following:

•Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG's generation assets' forecasted output or NRG's retail load obligations through 2034;

•Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2021; and

•Other energy derivatives instruments extending through 2029.

Also, as of December 31, 2020, NRG had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows:

•Load-following forward electric sale contracts extending through 2034;

•Power tolling contracts through 2037;

•Coal purchase contracts through 2021;

•Power transmission contracts through 2025;

•Natural gas transportation contracts and storage agreements through 2030; and

•Coal transportation contracts through 2029.

Interest Rate Swaps

NRG was exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG entered into interest rate swap agreements. As of December 31, 2019, NRG had no interest rate derivative instruments as a result of the early termination of such contracts in connection with the repayment of the 2023 Term Loan Facility during the second quarter of 2019.

During the fourth quarter of 2020, NRG entered into $1.6 billion of interest rate hedges associated with anticipated certain financing needs. As of December 31, 2020, the interest rate hedges were settled in connection with the issuance of fixed rate debt, resulting in a gain of $11 million that was recorded as a reduction to interest expense.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2020 and 2019. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.


(In millions)		Total Volume
Commodity	Units	December 31, 2020	December 31, 2019
Emissions	Short Ton	1	3
Renewables Energy Certificates	Certificates	5	1
Coal	Short Ton	2	10
Natural Gas	MMBtu	(286)	(181)

Power	MWh	57	38
Capacity	MW/Day	(1)	(1)

Fair Value of Derivative Instruments

The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:


	Fair Value
	Derivative Assets				Derivative Liabilities
(In millions)	December 31, 2020		December 31, 2019		December 31, 2020		December 31, 2019






Derivatives Not Designated as Cash Flow or Fair Value Hedges:


Commodity contracts current	$	560	$	860	$	499	$	781
Commodity contracts long-term	261		310		385		322

Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	821	$	1,170	$	884	$	1,103

The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting derivatives by counterparty master agreement level and collateral received or paid:


	Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets/Liabilities		Derivative Instruments		Cash Collateral (Held)/Posted		Net Amount
As of December 31, 2020
Commodity contracts:
Derivative assets	$	821	$	(658)	$	(5)	$	158
Derivative liabilities	(884)		658		—		(226)
Total commodity contracts	$	(63)	$	—	$	(5)	$	(68)


	Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets/Liabilities		Derivative Instruments		Cash Collateral (Held)/Posted		Net Amount
As of December 31, 2019
Commodity contracts:
Derivative assets	$	1,170	$	(909)	$	(7)	$	254
Derivative liabilities	(1,103)		909		73		(121)
Total commodity contracts	$	67	$	—	$	66	$	133

Accumulated Other Comprehensive Income

The following table summarizes the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax, for the year 2018:


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

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

Impact of Derivative Instruments on the Statement of Operations

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges are reflected in current period earnings.

The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges or fair value hedges and trading activity on the Company's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.


	Year Ended December 31,
(In millions)	2020		2019		2018
Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(55)	$	(68)	$	(73)
Reversal of acquired loss/(gain) positions related to economic hedges	4		6		(10)
Net unrealized (losses)/gains on open positions related to economic hedges	(68)		42		97
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(119)		(20)		14
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity	(20)		(11)		(12)

Net unrealized gains on open positions related to trading activity	15		31		29
Total unrealized mark-to-market (losses)/gains for trading activity	(5)		20		17
Total unrealized (losses)/gains	$	(124)	$	—	$	31


	Year Ended December 31,
(In millions)	2020		2019		2018
Unrealized gains/(losses) included in operating revenues	$	90	$	53	$	(113)
Unrealized (losses)/gains included in cost of operations	(214)		(53)		144
Total impact to statement of operations — energy commodities	$	(124)	$	—	$	31
Total impact to statement of operations — interest rate contracts	$	—	$	(38)	$	—

The reversal of gain or loss positions acquired as part of acquisitions were valued based upon the forward prices on the acquisition dates. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in revenue or cost of operations during the same period.

For the year ended December 31, 2020, the $68 million loss from open economic hedge positions was primarily the result of a decrease in the value of forward positions as a result of decreases in ERCOT power prices and heat rate contraction, partially offset by an increase in value of forward positions as a result of decreases in New York capacity prices.

The gains from open economic hedge positions of $42 million and $97 million for the years ended December 31, 2019 and 2018, respectively, were primarily the result of an increase in the value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Company to post additional collateral if there were a downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in net liability positions as of December 31, 2020 was $26 million. The Company is also a party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, which was approximately $35 million as of December 31, 2020. If called for by the counterparty, $1 million of additional collateral would be required for all contracts with credit rating contingent features as of December 31, 2020.

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

Nuclear Decommissioning Trust Fund

12 Months Ended

Dec. 31, 2020

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, 2020							As of December 31, 2019
(In millions, except otherwise noted)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted- average maturities (in years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted- average maturities (in years)
Cash and cash equivalents	$	23	$	—	$	—	—	$	17	$	—	$	—	—
U.S. government and federal agency obligations	70		6		—		10	68		4		—		11
Federal agency mortgage-backed securities	89		4		—		24	100		3		—		24
Commercial mortgage-backed securities	36		2		—		27	29		1		1		24
Corporate debt securities	144		13		—		12	109		6		—		11
Equity securities	521		372		—		—	466		324		—		—
Foreign government fixed income securities	7		1		—		10	5		—		—		10
Total	$	890	$	398	$	—		$	794	$	338	$	1

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined using the specific identification method.


	Year Ended December 31,
(In millions)	2020		2019		2018
Realized gains	$	34	$	18	$	17
Realized (losses)	(13)		(9)		(13)
Proceeds from sale of securities	439		381		513

Inventory

12 Months Ended

Dec. 31, 2020

Inventory Disclosure [Abstract]

Inventory

Inventory consisted of:


	As of December 31,
(In millions)	2020		2019
Fuel oil	$	37	$	73
Coal	73		93
Natural gas	22		21
Spare parts	195		196

Total Inventory	$	327	$	383

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2020

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

The Company recorded long-lived asset impairments during the years ended December 31, 2020 and 2019, as further described in Note 11, Asset Impairments. Depreciation expense of property, plant and equipment recorded during the years ended 2020, 2019 and 2018 was $295 million, $271 million and $356 million, respectively.

Leases

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Leases

The Company leases generating facilities, land, office and equipment, railcars, and storefront space at retail stores. Operating leases with an initial term greater than twelve months are recognized as right-of-use assets and lease liabilities in the consolidated balance sheets. The Company made an accounting policy election for all asset classes not to recognize right-of-use assets and lease liabilities in the consolidated balance sheets for its short-term leases, which are leases that have a lease term of twelve months or less. The Company recognizes lease expense for all operating leases on a straight-line basis over the lease term. In the future, should another systematic basis become more representative of the pattern in which the lessee expects to consume the remaining economic benefit of the right-of-use asset, the Company will use that basis for lease expense.

The Company considers a contract to be or to contain a lease when both of the following conditions apply: 1) an asset is either explicitly or implicitly identified in the contract and 2) the contract conveys to the Company the right to control the use of the identified asset for a period of time. The Company has the right to control the use of the identified asset when the Company has both the right to obtain substantially all the economic benefits from the use of the identified asset and the right to direct how and for what purpose the identified asset is used throughout the period of use.

Lease payments are typically fixed and payable on a monthly, quarterly, semi-annual or annual basis. Lease payments under certain agreements may escalate over the lease term either by a fixed percentage or a fixed dollar amount. Certain leases may provide for variable lease payments in the form of payments based on usage, a percentage of sales from the location under lease, or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments. The Company has no leases which contain residual value guarantees provided by the Company as a lessee.

The Company’s leases may grant the Company an option to renew a lease for an additional term(s) or to terminate the lease after a certain period. As part of its transition from the guidance contained in ASC 840 to the updated guidance in ASC 842, the Company elected not to use the practical expedient of using hindsight to determine the lease term and in assessing impairment of the right-of-use assets.

As permitted by ASC 842, the Company made an accounting policy election for all asset classes not to recognize right-of-use assets and lease liabilities in the consolidated balance sheets for its short-term leases, which are leases that have a lease term of twelve months or less. For the initial measurement of lease liabilities, the discount rate that the Company uses is either the rate implicit in the lease, if known, or its incremental borrowing rate, which is the rate of interest that the Company would have to pay to borrow, on a collateralized basis, over a similar term an amount equal to the payments for the lease.

In transition to ASC 842, the Company elected to apply the effective date transition method as of the January 1, 2019 adoption date. In accordance with this method, the Company’s reporting for comparative periods prior to January 1, 2019 presented in the financial statements continues to be in conformity with the guidance in ASC 840. The Company elected the following practical expedients, which allow entities to:

•Not reassess whether any contracts that existed prior to the January 1, 2019 implementation date are or contain leases;

•Not reassess the lease classification for any leases that commenced prior to the January 1, 2019 implementation date, meaning that all commenced capital leases under ASC 840 will be classified as finance leases under ASC 842 and all commenced operating leases under ASC 840 will be classified as operating leases under ASC 842;

•Not reassess initial direct costs for any leases;

•Not reassess whether existing land easements, which were not previously accounted as leases under ASC 840, are or contain leases; and

•Not separate lease and non-lease components for all asset classes, except office space leases and generation facilities leases.

As described in Note 4, Acquisitions, Discontinued Operations and Dispositions, upon the close of the South Central Portfolio sale in 2019, the Company entered into an agreement to leaseback the Cottonwood facility through May 2025. The lease was accounted for in accordance with ASC 842-40, Sale and Leaseback Transactions, as an operating lease and accordingly, a right-of-use asset and lease liability were established on the lease commencement date and will be amortized through the end of the lease.

Lease Cost:


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


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

Other information:


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

Cash paid for amounts included in the measurement of lease liabilities:


Operating cash flows from operating leases	$	101	$	104
Financing cash flows from finance leases	1		—
Right-of-use assets obtained in exchange for new finance lease liabilities	5		—
Right-of-use assets obtained in exchange for new operating lease liabilities	4		215

Lease Term and Discount Rate for leases:


	December 31, 2020		December 31, 2019
Finance leases:
Weighted average remaining lease term (in years)	1.1		—
Weighted average discount rate	4.79	%	—

Operating leases:
Weighted average remaining lease term (in years)	5.3		7.8
Weighted average discount rate	5.63	%	5.72	%

As of December 31, 2020, annual payments based on the maturities of NRG's leases are expected to be as follows:


	(In millions)
2021	$	86
2022	82
2023	81
2024	71
2025	47
Thereafter	34
Total undiscounted lease payments	$	401
Less: present value adjustment	(54)
Total discounted lease payments	$	347

Asset Impairments	12 Months Ended
Asset Impairments	Dec. 31, 2020
Asset Impairment Charges [Abstract]
Asset Impairments	Asset Impairments 2020 Impairment Losses During the fourth quarter of 2020, the Company completed its annual budget and revised its view of long-term power and fuel prices and the corresponding impact on estimated cash flows associated with its long-lives assets. The Cottonwood facility had estimated cash flows that were lower than its carrying amount and the assets were considered impaired. The fair value of the assets was determined using an income approach by applying a discounted cash flow methodology to the long-term budget for the facility. The income approach utilized estimates of after-tax cash flows, which were Level 3 fair value measurements, and included key inputs such as forecasted power prices, fuel costs, operating and maintenance costs, plant investment capital expenditures and discount rates. The Cottonwood facility is being leased through 2025 and the Company recognized an impairment loss of $32 million in 2020 in the West/Other segment associated with the Company's long-term services agreement and related lease payments, as the carrying amounts of the assets from the contract were higher than the estimated operating cash flow though the remaining lease period. The Company also recorded the following impairments in 2020 based on specific triggering events that occurred: Home Solar — In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $29 million in the West/Other segment to adjust the carrying amount of the assets and liabilities to fair market value based on indicative sale prices. Petra Nova Parish Holdings — During the first quarter of 2020, due to the decline in oil prices, NRG determined that the carrying amount of the Company’s equity method investment exceeded the fair value of the investment and that the decline is considered to be other-than-temporary. In determining the fair value, the Company utilized an income approach to estimate future project cash flows. The Company recorded an impairment loss of $18 million in the Texas segment, which included the anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover certain project debt reserve requirements. Other Impairments — For the year ended December 31, 2020, the Company recorded $14 million of impairment losses related to intangible assets in the Texas segment. 2019 Impairment Losses Petra Nova Parish Holdings — During the third quarter of 2019, NRG contributed $95 million in cash to Petra Nova and posted a $12 million letter of credit to cover certain project debt reserve requirements. The cash portion of the contribution was used by Petra Nova to prepay a significant portion of the project debt. As a result, the previously disclosed guarantee of up to $124 million related to the project level debt provided by NRG was canceled and the remaining project debt became non-recourse to NRG. In relation to this contribution, the Company evaluated the project for impairment and determined that the carrying amount of the Company’s equity method investment exceeded the fair value of the investment and that the decline is considered to be other-than-temporary. In determining the fair value, the Company utilized an income approach and considered project specific assumptions for the estimated future project cash flows. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $101 million. Other Impairments — For the year ended December 31, 2019, the Company recorded $12 million of impairment losses primarily related to investments and intangibles. 2018 Impairment Losses Guam — During the fourth quarter of 2018, the Company concluded its wholly-owned subsidiary, NRG Solar Guam, LLC, was held for sale after board approval and advanced negotiations to sell the business. Accordingly, the Company recorded the assets and liabilities at fair market value as of December 31, 2018 based on the contractual sale price, which resulted in an impairment loss of $12 million. On February 20, 2019, the Company completed the sale of Guam for cash consideration of approximately $8 million. Keystone and Conemaugh — On September 5, 2018, the Company sold its approximately 3.7% interests in the Keystone and Conemaugh generating stations. NRG recorded impairment losses of $14 million for Keystone and $14 million for Conemaugh to adjust the carrying amount of the assets to fair value based on the contractual sale price. Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against the NYPSC, which challenged the legality of its contract with Dunkirk. The lawsuit was later dropped and development continued, but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection study process. The NYISO studies have concluded that extensive electric system upgrades would be necessary for the station to return to service. This would cause the Company to incur a material increase in cost and delay the project schedule that would render the project impractical. Consequently, the Company has recorded an impairment loss of $46 million, reducing the carrying amount of the related assets to $0. Other Impairments — As of December 31, 2018, the Company recorded additional asset impairment losses of $13 million and impairment losses on equity method investments of $15 million.

Goodwill and Other Intangibles

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Other Intangibles

Goodwill

NRG's goodwill balance was $579 million as of December 31, 2020 and 2019. As of December 31, 2020, goodwill consisted of $165 million associated with the acquisition of Midwest Generation and $414 million for retail operations acquisitions, including Stream Energy and XOOM, which were acquired in 2019 and 2018, respectively.

Intangible Assets

The Company's intangible assets as of December 31, 2020, primarily reflect intangible assets established with the acquisitions of various companies, including Stream Energy, XOOM, other retail acquisitions, and Texas Genco. Intangible assets are comprised of the following:

•Emission Allowances — These intangibles primarily consist of SO2 emission allowances, including those established with the 2006 acquisition of Texas Genco, RGGI emission credits and California carbon allowances. These emission allowances are held-for-use and are amortized to cost of operations based on units of production.

•In-market nuclear fuel contracts — These intangibles were established with the Texas Genco acquisition in 2006 and are amortized to cost of operations over expected volumes over the life of each contract.

•Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.

•Marketing partnerships — These intangibles represent the fair value at the acquisition date of existing agreements with marketing vendors and loyalty and affinity partners for customer acquisition. The marketing partnerships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.

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

•Other — Consists of renewable energy credits, costs to extend the operating license for STP Units 1 and 2, and energy supply contracts acquired with Stream Energy that represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers. Renewable energy credits are retired, as required, for the applicable compliance period. They are expensed to cost of operations based on NRG’s customer usage. Energy supply contracts are amortized to depreciation and amortization based on the expected delivery under the respective contracts.

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


(In millions)
Year Ended December 31, 2020	Emission Allowances		Fuel Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other(b)		Total
January 1, 2020	$	662	$	49	$	573	$	285	$	373	$	109	$	2,051
Purchases	25		—		—		—		—		45		70
Acquisition of businesses (a)	—		—		22		—		—		—		22
Retirements	—		—		—		—		—		(35)		(35)
Write-off of fully amortized balances	(4)		—		(70)		—		—		—		(74)
Impairment	(14)		—		—		—		—		—		(14)
Other	3		—		2		—		—		—		5
December 31, 2020	672		49		527		285		373		119		2,025
Less accumulated amortization	(563)		(46)		(349)		(99)		(247)		(53)		(1,357)
Net carrying amount	$	109	$	3	$	178	$	186	$	126	$	66	$	668

(a)The weighted average life of acquired intangibles was 5 years for customer relationships

(b)RECs are not subject to amortization and had a carrying value of $28 million


(In millions)
Year Ended December 31, 2019	Emission Allowances		Fuel Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other(b)		Total
January 1, 2019	$	659	$	49	$	478	$	131	$	345	$	80	$	1,742
Purchases	13		—		—		—		—		29		42
Acquisition of businesses (a)	—		—		110		154		28		26		318
Usage/Retirements	(4)		—		—		—		—		(17)		(21)
Write-off of fully amortized balances	(8)		—		(13)		—		—		(9)		(30)
Impairment	—		—		(2)		—		—		—		(2)
Other	2		—		—		—		—		—		2
December 31, 2019	662		49		573		285		373		109		2,051
Less accumulated amortization	(539)		(45)		(345)		(75)		(220)		(38)		(1,262)
Net carrying amount	$	123	$	4	$	228	$	210	$	153	$	71	$	789

(a)The weighted average life of acquired intangibles was: customer relationships 7 years, trade names 12 years, marketing partnerships 9 years, and energy supply contracts 2 years

(b)RECs are not subject to amortization and had a carrying value of $18 million

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


	Years Ended December 31,
(In millions)	2020		2019		2018
Emission allowances	$	28	$	32	$	39
Customer relationships	74		44		32
Marketing partnerships	24		15		9
Trade names	27		25		23
Other(a)	51		35		30
Total amortization	$	204	$	151	$	133

(a)For the years ended December 31, 2020, 2019 and 2018, RECs were retired to cost of operations for $36 million, $17 million and $28 million, respectively. For the years ended December 31, 2020, 2019 and 2018, other intangibles were amortized to depreciation and amortization expense for $15 million, $18 million and $2 million, respectively.

The following table presents estimated amortization of NRG's intangible assets as of December 31, 2020 for each of the next five years:


(In millions)
Year Ended December 31,	Emission Allowances		Fuel Contracts		Customer Relationships		Marketing Partnerships		Trade Names		Other		Total
2021	$	31	$	—	$	64	$	24	$	27	$	3	$	149
2022	30		1		44		23		27		3		128
2023	30		—		45		23		26		3		127
2024	31		1		16		23		17		3		91
2025	29		—		5		22		11		3		70

Intangible assets held-for-sale — From time to time, management may authorize the transfer from the Company's emission bank of emission allowances held-for-use to intangible assets held-for-sale. Emission allowances held-for-sale are included in other non-current assets on the Company's consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31, 2020 and 2019, the value of emission allowances held-for-sale was $14 million and $6 million, respectively, within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.

Receivables Securitization and Repurchase Facility

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Receivable Securitization and Repurchase Facility

Receivables Securitization and Repurchase Facility

Receivables Securitization

On September 22, 2020, NRG Receivables LLC, a bankruptcy remote, special purpose, indirect wholly owned subsidiary, entered into the Receivables Facility for an amount up to $750 million, subject to adjustments on a seasonal basis, with issuers of asset-backed commercial paper and commercial banks (the "Lenders".) The assets of NRG Receivables LLC are first available to satisfy the claims of the Lenders before making payments on the subordinated note and equity issued by NRG Receivables LLC. The assets of NRG Receivables LLC are not available to the Company and its subsidiaries or creditors unless and until distributed by NRG Receivables LLC. Under the Receivables Facility, certain indirect subsidiaries of the Company sell their accounts receivables to NRG Receivables LLC, subject to certain terms and conditions. In turn, NRG Receivables LLC grants a security interest in the purchased receivables to the Lenders as collateral for cash borrowings and issuances of letters of credit. Pursuant to the Performance Guaranty, the Company has guaranteed, for the benefit of NRG Receivables and the lenders, the payment and performance by each indirect subsidiary of its respective obligations under the Receivables Facility. The accounts receivables remain on the Company's consolidated balance sheet and any amounts funded by the Lenders to NRG Receivables LLC will be reflected as short-term borrowings. Cash flows from the Receivables Facility are reflected as financing activities in the Company's consolidated statements of cash flows. The Company will continue to service the accounts receivables sold in exchange for a servicing fee. The Receivables Facility is scheduled to expire on September 21, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. Borrowings by NRG Receivables LLC under the Receivables Facility bear interest as defined under the Receivables Financing Agreement. The weighted average interest rate related to usage under the Securitization Facility as of December 31, 2020 was 0.537%. As of December 31, 2020, there were no outstanding borrowings and there were $198 million in letters of credit issued under the Receivables Facility.

Repurchase Facility

On September 22, 2020, the Company entered into an uncommitted repurchase facility (“Repurchase Facility”) related to the Receivables Facility. Under the Repurchase Facility, the Company can borrow up to $75 million, collateralized by a

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. The Repurchase Facility is scheduled to expire on September 22, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. The Repurchase Facility has no commitment fee and borrowings will be drawn at LIBOR + 1.25%. As of December 31, 2020, there were no outstanding borrowings under the Repurchase Facility.Long-term Debt and Finance Leases

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


(In millions, except rates)	December 31, 2020		December 31, 2019		Interest rate %

Recourse debt:
Senior Notes, due 2026	$	1,000	$	1,000	7.250
Senior Notes, due 2027	1,230		1,230		6.625
Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	733		733		5.250
Senior Notes, due 2029	500		—		3.375
Senior Notes, due 2031	1,030		—		3.625
Convertible Senior Notes, due 2048(a)	575		575		2.750
Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2025	500		—		2.000
Senior Secured First Lien Notes, due 2027	900		—		2.450
Senior Secured First Lien Notes, due 2029	500		500		4.450
Revolving Credit Facility	—		83		L+ 1.75
Tax-exempt bonds	466		466		1.250 - 4.75
Subtotal recourse debt	8,855		6,008
Non-recourse debt:
Other	—		34		various
Subtotal all non-recourse debt	—		34
Subtotal long-term debt (including current maturities)	8,855		6,042
Finance leases	4		—		various

Subtotal long-term debt and finance leases (including current maturities)	8,859		6,042
Less current maturities	(1)		(88)
Less debt issuance costs	(93)		(65)
Discounts	(74)		(86)
Total long-term debt and finance leases	$	8,691	$	5,803

(a)The effective interest rate was 5.19% and 5.05% for the years ended December 31, 2020 and 2019, respectively. As of the ex-dividend date of January 29, 2021, the Convertible Notes were convertible at a price of $45.94, which is equivalent to a conversion rate of approximately 21.77 shares of common stock per $1,000 principal amount. The remaining period over which the discount on the liability component will be amortized is 4.7 years.

Debt includes the following discounts:


	As of December 31,
(In millions)	2020		2019
Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029	$	(2)	$	(1)
Convertible Senior Notes, due 2048	(72)		(85)
Total discounts	$	(74)	$	(86)

Consolidated Annual Maturities

As of December 31, 2020, annual payments based on the maturities of NRG's debt and finance leases are expected to be as follows:


	(In millions)
2021	$	1
2022	2
2023	1
2024	600
2025	500
Thereafter	7,755
Total	$	8,859

Recourse Debt

Senior Notes

Issuance of 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes

On December 2, 2020, NRG issued $500 million aggregate principal amount of 3.375% senior notes due 2029 (the “2029 Unsecured Notes”) and $1.0 billion aggregate principal amount of 3.625% senior notes due 2031 (the “2031 Unsecured Notes” and, together with the 2029 Unsecured Notes, the “Unsecured Notes”). Interest is payable on the Unsecured Notes on February 15 and August 15 of each year beginning on August 15, 2021 until the maturity date of February 15, 2029 for the 2029 Unsecured Notes and February 15, 2031 for the 2031 Unsecured Notes.

Issuance of 2025 and 2027 Senior Secured First Lien Notes

On December 2, 2020, NRG issued $1.4 billion of aggregate principal amount of senior secured first lien notes, consisting of $500 million 2.000% senior secured first lien notes due 2025 (the “2025 Secured Notes”) and $900 million 2.450% senior secured first lien notes due 2027 (the “2027 Secured Notes” and, together with the 2025 Secured Notes, the “2025 and 2027 Senior Secured First Lien Notes”), at a discount. The 2027 Secured Notes were issued under NRG’s Sustainability-Linked Bond Framework, which sets out certain sustainability targets, including reducing greenhouse gas emissions. Failure to meet such sustainability targets will result in a 25 basis point increase to the interest rate payable on the 2027 Secured Notes from and including the interest period ending on June 2, 2026. The 2025 and 2027 Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The 2025 and 2027 Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the 2025 and 2027 Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade. Interest is payable on the 2025 and 2027 Senior Secured First Lien Notes on June 2 and December 2 of each year beginning on June 2, 2021 until the maturity date of December 2, 2025 for the 2025 Secured Notes and until the maturity date of December 2, 2027 for the 2027 Secured Notes.

Issuance of 2029 Senior Notes

On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029, or the 2029 Senior Notes. The 2029 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity date of June 15, 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining 6.25% Senior Notes due 2024.

Issuance of 2024 and 2029 Senior Secured First Lien Notes

On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 2.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Senior Secured First Lien Notes, at a discount. The Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Senior Secured First Lien Notes will be released if the Company obtains an

investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity dates of June 15, 2024 and June 15, 2029. The proceeds from the issuance of the Senior Secured First Lien Notes, together with cash on hand, were used to repay the Company's 2023 Term Loan Facility.

2019 Senior Note Redemptions

During the year ended December 31, 2019, the Company redeemed $733 million of its 6.25% Senior Notes due 2024 and recorded a loss on debt extinguishment of $29 million, which included the write-off of previously deferred debt issuance costs of $5 million.

2048 Convertible Senior Notes

The Convertible Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options. Under ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The Convertible Notes are convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at a price of $46.24 per common share as of December 31, 2020, which is equivalent to an conversion rate of approximately 21.6242 shares of common stock per $1,000 principal amount of Convertible Notes. As of December 31, 2019, the Convertible Notes were convertible at a price of $47.74 per common share, which is equivalent to an conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of Convertible Notes. The carrying amounts of the liability components as of December 31, 2020 and 2019 of $503 million and $491 million, respectively, were calculated by estimating the fair value of similar liabilities without a conversion feature at inception and amortizing the debt discount using the effective interest rate over the life of the note.

Senior Notes Early Redemption

As of December 31, 2020, NRG had the following outstanding issuances of senior notes with an early redemption feature, or Senior Notes:

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

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

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

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

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

vi.3.625% senior notes, issued December 2, 2020 and Due February 15, 2031, or the 2031 Senior Notes.

The Company periodically enters into supplemental indentures for the purpose of adding entities under the Senior Notes as guarantors.

The indentures and the forms of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG. The indentures also provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRG and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately. The terms of the indentures, among other things, limit NRG's ability and certain of its subsidiaries' ability to return capital to stockholders, grant liens on assets to lenders and incur additional debt. Interest is payable semi-annually on the Senior Notes until their maturity dates.

2026 Senior Notes

At any time prior to May 15, 2021, NRG may redeem all or a part of the 2026 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.625% of the note, plus interest payments due on the note from the date of redemption through May 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after May 15, 2021, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Redemption Period	Redemption Percentage
May 15, 2021 to May 14, 2022	103.625	%
May 15, 2022 to May 14, 2023	102.417	%
May 15, 2023 to May 14, 2024	101.208	%
May 15, 2024 and thereafter	100.000	%

2027 Senior Notes

At any time prior to July 15, 2021, NRG may redeem all or a part of the 2027 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on the note from the date of redemption through July 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50%. In addition, on or after July 15, 2021, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Redemption Period	Redemption 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, 2021, NRG may redeem up to 35% of the aggregate principal amount of the 2028 Senior Notes, at a redemption price equal to 105.750% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to January 15, 2023, NRG may redeem all or a part of the 2028 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 102.875% of the note, plus interest payments due on the note from the date of redemption through January 15, 2023 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50%. In addition, on or after January 15, 2023, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Redemption Period	Redemption 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 accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 102.625% of the note, plus interest payments due on the note through June 15, 2024 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after June 15, 2024, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Redemption Period	Redemption Percentage
June 15, 2024 to June 14, 2025	102.625	%
June 15, 2025 to June 14, 2026	101.750	%
June 15, 2026 to June 14, 2027	100.875	%
June 15, 2027 and thereafter	100.000	%

3.375% 2029 Senior Notes

At any time prior to February 15, 2024, NRG may redeem up to 40% of the aggregate principal amount of the 2029 Senior Notes, at a redemption price equal to 103.375% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15, 2024, NRG may redeem all or a part of the 2029 Senior Notes, at a redemption price equal to 100% of the principal amount accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 101.688% of the note, plus interest payments due on the note through February 15, 2024 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after February 15, 2024, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Redemption Period	Redemption Percentage
February 15, 2024 to February 14, 2025	101.688	%
February 15, 2025 to February 14, 2026	100.844	%
February 15, 2026 and thereafter	100.000	%

2031 Senior Notes

At any time prior to February 15, 2026, NRG may redeem up to 40% of the aggregate principal amount of the 2031 Senior Notes, at a redemption price equal to 103.625% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15, 2026, NRG may redeem all or a part of the 2031 Senior Notes, at a redemption price equal to 100% of the principal amount accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 101.813% of the note, plus interest payments due on the note through February 15, 2026 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after February 15, 2026, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:


Redemption Period	Redemption Percentage
February 15, 2026 to February 14, 2027	101.813	%
February 15, 2027 to February 14, 2028	101.208	%
February 15, 2028 to February 14, 2029	100.604	%
February 15, 2029 and thereafter	100.000	%

Senior Credit Facility

2023 Term Loan Facility Repayment

On May 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior First Lien Notes, as well as cash on hand, resulting in a decrease of $594 million to long-term debt outstanding. The Company recorded a loss on debt extinguishment of $17 million, which included the write-off of previously deferred debt issuance costs of $13 million. As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $25 million that was recorded as a reduction to interest expense.

Revolving Credit Facility Modification

On May 28, 2019, the Company amended its existing credit agreement to, among other thing, (i) provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion, (ii) extend the maturity date of the revolving loans and commitments under the amended credit agreement to May 28, 2024, (iii) provide for a release of the collateral securing the amended credit agreement if NRG obtains an investment grade rating form two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw NRG's investment grade rating or downgrade NRG's rating below investment grade, (iv) reduce the applicable margins for borrowings under (a) ABR Revolving Loans from 1.25% to 0.75% and (b) Eurodollar Revolving Loans from 2.25% to 1.75%, (v) add a sustainability covenant and (vi) make certain other changes to the existing covenants.

On August 20, 2020, the Company amended its existing credit agreement to, among other things, (i) increase the existing revolving commitments in an aggregate amount of $802 million, (ii) provide for a new tranche of revolving commitments in an aggregate amount of $273 million with a maturity date that is 30 months after the Acquisition Close Date. The maturity date of the new revolving tranche of commitments may, upon request by the Company, at the option of each applicable lender under the new tranche be extended by a further 12 months, but not beyond May 28, 2024, which is the maturity date of the existing and increased commitments. Other than with respect to the maturity date, the terms of all revolving commitments and loan made pursuant thereto are identical. The increase in the existing commitments, and the commitments with respect to the new tranche, are effective on August 20, 2020 but only became available on the Acquisition Closing Date. For further discussion on the acquisition of Direct Energy see Note 4, Acquisitions, Discontinued Operations and Dispositions. Upon the Acquisition Closing Date, total revolving commitments available, subject to usage, under this amendment will be $3.7 billion.

In addition, the amendment includes changes to, among other things, (i) permit the borrowing of up to full amount of the revolving commitments in Canadian dollars, (ii) increase the swingline facility from $50 million to $100 million and provide a $10 million swingline facility in Canadian dollars, (iii) increase the credit facilities lien basket from the greater of $6 billion and 30% of total assets to the greater of $10 billion and 30% of total assets, (iv) increase the credit facilities debt basket from $6 billion to $10 billion, (v) increase the basket for securitization indebtedness from $750 million to $1.7 billion, (vi) provide an additional indebtedness basket equal to $600 million for certain liquidity facilities, and (vii) make certain other changes to the existing covenants and other provisions.

Tax Exempt Bonds


	As of December 31,
(In millions, except rates)	2020		2019		Interest Rate %
NRG Indian River Power 2020, tax exempt bonds, due 2040	$	57	$	—	1.250
NRG Indian River Power 2020, tax exempt bonds, due 2045	190		—		1.250
Indian River Power, tax exempt bonds, due 2040	—		57		6.000
Indian River Power LLC, tax exempt bonds, due 2045	—		190		5.375
NRG Dunkirk 2020, tax exempt bonds, due 2042	59		—		1.300
Dunkirk Power LLC, tax exempt bonds, due 2042	—		59		5.875
City of Texas City, tax exempt bonds, due 2045	33		33		4.125
Fort Bend County, tax exempt bonds, due 2038	54		54		4.750
Fort Bend County, tax exempt bonds, due 2042	73		73		4.750
Total	$	466	$	466

Dunkirk Bonds

On March 11, 2020, NRG issued $59 million in aggregate principal amount of NRG Dunkirk 2020 1.30% tax-exempt refinancing bonds due 2042 (the "Dunkirk Bonds"). The Dunkirk Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Dunkirk Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Dunkirk Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The Dunkirk Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042.

NRG used the net proceeds from the offering to redeem during 2020 the existing principal amount of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042.

Indian River Bonds

On December 17, 2020, NRG issued $57 million in aggregate principal amount of NRG Indian River 2020 1.25% tax-exempt refinancing bonds due 2040 (the "IR 2040 Bonds") and $190 million aggregate principal amount of NRG Indian River Power 2020 1.25% tax-exempt refinancing bonds due 2045 (the "IR 2045 Bonds") (together the "IR Bonds"). The IR Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The IR Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the IR Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the IR Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The IR Bonds are subject to mandatory tender and purchase on October 1, 2025 and have final maturity dates of October 1, 2040 for the IR 2040 Bonds and October 1, 2045 for the IR 2045 Bonds.

NRG used the net proceeds from the offering to redeem during 2020 the existing principal amounts of outstanding Indian River Power 6.000% tax exempt bonds due 2040 and Indian River Power LLC 5.375% tax exempt bonds due 2045.

Non-Recourse Debt

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

Credit Default Swap Facility

On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease. Annual fees of 1.33% on the facility were paid quarterly in advance. On August 13, 2020, the agreement was amended permitting the Company to increase the size of the facility and fees on the facility were adjusted to reflect the costs of the credit default swaps that serve as collateral for the facility. In order to increase the Company’s collective collateral facilities in connection with the Direct Energy acquisition, NRG expanded the facility allowing for the issuance of an additional $150 million of letters of credit as of December 31, 2020. As of December 31, 2020, $229 million was issued under this facility.

Bilateral Letter of Credit Facilities

In December 2020 the Company entered into a series of Bilateral Letter of Credit Facilities to allow for the issuance of up to $475 million of letters of credit. These facilities are uncommitted. As of December 31, 2020, $5 million was issued under these facilities.

Put Option Agreement for Senior Debt Issuance

During the fourth quarter of 2020, the Company entered into a 3-year put option agreement with a Delaware trust formed by the Company upon completion of the sale of $900 million pre-capitalized trust securities redeemable November 15, 2023 (the “P-Caps”). The Trust invested the proceeds from the sale of the P-Caps in a portfolio of principal and interest strips of U.S. Treasury securities (the “Eligible Treasury Assets”). Under the put option agreement, NRG has the right, from time to time, to issue to the Trust and to require the Trust to purchase from NRG, on one or more occasions (the “Issuance Right”), up to $900 million aggregate principal amount of NRG’s 1.841% Senior Secured First Lien Notes due 2023 (the “P-Caps Secured Notes”) in exchange for all or a portion of the Eligible Treasury Assets corresponding to the portion of the Issuance Right. NRG will pay a semi-annual premium to the Trust at a rate of 1.65%.

The P-Caps are to be redeemed by the Trust on November 15, 2023 or earlier upon an early redemption of the P-Caps Secured Notes. Following any distribution of P-Caps Secured Notes to the holders of the P-Caps, NRG may similarly redeem such P-Caps Secured Notes, in whole or in part, at the redemption price described below, plus accrued but unpaid interest to, but excluding, the date of redemption. Any P-Caps Secured Notes outstanding and held by the Trust as a result of the exercise of the Issuance Right that remain outstanding will also mature on November 15, 2023.

The Issuance Right will be exercised automatically in full if (1) NRG fails to pay the facility fee when due or any amount due and owing under the trust expense reimbursement agreement or fails to purchase and pay for any Eligible Treasury Assets that are due and not paid on their payment date and such failure is not cured within 30 days, or (2) upon certain bankruptcy events of NRG.

NRG will be required to mandatorily exercise the Issuance Right if (1) an Acquisition Triggering Event has occurred, (2) NRG’s consolidated stockholders’ equity, determined in accordance with GAAP, but excluding accumulated other comprehensive income (or loss), equity of non-controlling interests attributable thereto and treasury stock at cost, has fallen below $2.0 billion, which amount may be adjusted from time to time upon the occurrence of certain specified events, (3) an event of default under the P-Caps Secured Notes Indenture (as defined below) has occurred or would have occurred had the P-Caps Secured Notes been outstanding, (4) NRG breaches its covenant to maintain sufficient capacity under other material agreements to permit the issuance of the P-Caps Secured Notes in full, (5) a Collateral Enforcement Event (as defined below) has occurred, (6) a change of control triggering event has occurred in respect of NRG or (7) certain events relating to the Trust’s status as an “investment company” under the Investment Company Act of 1940, as amended (the “Investment Company Act”), have occurred. Upon the occurrence of any event described in clause (1), (2), (3), (4) or (7) of this paragraph, the Issuance Right will be exercised in full, and upon the occurrence of any event described in clause (5) or (6) of this paragraph, the Issuance Right will be exercised with respect to the applicable portion of the available amount of P-Caps Secured Notes specified in the Facility Agreement.

In connection with the issuance of the P-Caps, on December 2, 2020, NRG entered into a facility agreement for the issuance of letters of credit (the “LC Agreement”) and Deutsche Bank Trust Company Americas as collateral agent (the “Collateral Agent”) and administrative agent pursuant to which certain financial institutions (the “LC Issuers”) are permitted to join with commitments 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 currently outstanding letters of credit and other credit support issued for the account of entities being acquired pursuant to the Acquisition. In addition, on December 2, 2020, the Trust entered into a 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 (a “Collateral Enforcement Event”). As of December 31, 2020 no letters of credit were issued under this agreement.

Agua Caliente Borrower 1

On January 22, 2019, the lenders of the Agua Borrower 1 notes notified Agua Caliente Borrower 1, a subsidiary of the Company, of certain defaults under the financing agreement as it relates to the bankruptcy filing made by PG&E on January 29, 2019. PG&E is the offtaker of the underlying contracts, which are material to the project. The financing was entered into along with Agua Caliente Borrower 2, LLC, a subsidiary of Clearway Energy Inc., which is joint and several to the parties. On

October 21, 2019, the Company repaid the outstanding amount on the notes at 102% plus accrued interest through the payment date of $83 million.

Long-term Debt and Finance Leases

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Long-term Debt and Finance Leases

Receivables Securitization and Repurchase Facility

Receivables Securitization

Repurchase Facility

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


(In millions, except rates)	December 31, 2020		December 31, 2019		Interest rate %

Recourse debt:
Senior Notes, due 2026	$	1,000	$	1,000	7.250
Senior Notes, due 2027	1,230		1,230		6.625
Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	733		733		5.250
Senior Notes, due 2029	500		—		3.375
Senior Notes, due 2031	1,030		—		3.625
Convertible Senior Notes, due 2048(a)	575		575		2.750
Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2025	500		—		2.000
Senior Secured First Lien Notes, due 2027	900		—		2.450
Senior Secured First Lien Notes, due 2029	500		500		4.450
Revolving Credit Facility	—		83		L+ 1.75
Tax-exempt bonds	466		466		1.250 - 4.75
Subtotal recourse debt	8,855		6,008
Non-recourse debt:
Other	—		34		various
Subtotal all non-recourse debt	—		34
Subtotal long-term debt (including current maturities)	8,855		6,042
Finance leases	4		—		various

Subtotal long-term debt and finance leases (including current maturities)	8,859		6,042
Less current maturities	(1)		(88)
Less debt issuance costs	(93)		(65)
Discounts	(74)		(86)
Total long-term debt and finance leases	$	8,691	$	5,803

Debt includes the following discounts:


	As of December 31,
(In millions)	2020		2019
Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029	$	(2)	$	(1)
Convertible Senior Notes, due 2048	(72)		(85)
Total discounts	$	(74)	$	(86)

Consolidated Annual Maturities

As of December 31, 2020, annual payments based on the maturities of NRG's debt and finance leases are expected to be as follows:


	(In millions)
2021	$	1
2022	2
2023	1
2024	600
2025	500
Thereafter	7,755
Total	$	8,859