10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the Quarterly Period Ended:	March 31, 2022
☐	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware	41-1724239
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

910 Louisiana Street	Houston	Texas	77002
(Address of principal executive offices)			(Zip Code)

(713) 537-3000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading Symbol(s)	Name of Exchange on Which Registered
Common Stock, par value $0.01	NRG	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒       No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒       No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐  

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐       No ☒

As of April 30, 2022, there were 237,283,560 shares of common stock outstanding, par value $0.01 per share.

1

TABLE OF CONTENTS

Index

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	5
PART I — FINANCIAL INFORMATION	8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	34
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	58
ITEM 4 — CONTROLS AND PROCEDURES	61
PART II — OTHER INFORMATION	62
ITEM 1 — LEGAL PROCEEDINGS	62
ITEM 1A — RISK FACTORS	62
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	62
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	62
ITEM 4 — MINE SAFETY DISCLOSURES	62
ITEM 5 — OTHER INFORMATION	62
ITEM 6 — EXHIBITS	63
SIGNATURES	64

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risk Factors, in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2021 and the following:

•Business uncertainties related to the integration of the operations of Direct Energy with its own;

•NRG's ability to obtain and maintain retail market share;

•General economic conditions, changes in the wholesale power and gas markets and fluctuations in the cost of fuel;

•Volatile power and gas supply costs and demand for power and gas;

•Changes in law, including judicial and regulatory decisions;

•Hazards customary to the power production industry and power generation operations, such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;

•The effectiveness of NRG's risk management policies and procedures and the ability of NRG's counterparties to satisfy their financial commitments;

•NRG's ability to enter into contracts to sell power or gas and procure fuel on acceptable terms and prices;

•NRG's inability to estimate with any degree of certainty the future impact that COVID-19, any resurgence of COVID-19 or variants thereof, or other pandemic may have on NRG's results of operations, financial position, risk exposure and liquidity;

•NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses;

•NRG's ability to engage in successful acquisitions and divestitures, as well as other mergers and acquisitions activity;

•Cyber terrorism and cybersecurity risks, data breaches or the occurrence of a catastrophic loss and the possibility that NRG may not have sufficient insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage;

•Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;

•NRG's ability to operate its businesses efficiently and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;

•The liquidity and competitiveness of wholesale markets for energy commodities;

•Government regulation, including changes in market rules, rates, tariffs and environmental laws;

•NRG's ability to develop and innovate new products, as retail and wholesale markets continue to change and evolve;

•Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;

•NRG's ability to mitigate forced outage risk;

•NRG's ability to borrow funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness in the future;

•Operating and financial restrictions placed on NRG and its subsidiaries that are contained in NRG's corporate credit agreements, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;

•The ability of NRG and its counterparties to develop and build new power generation facilities;

•NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources, while taking advantage of business opportunities;

•NRG's ability to increase cash from operations through operational and market initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;

•NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;

•NRG's ability to develop and maintain successful partnering relationships as needed.

3

Forward-looking statements speak only as of the date they were made and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.

4

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

2021 Form 10-K	NRG’s Annual Report on Form 10-K for the year ended December 31, 2021
ACE	Affordable Clean Energy
AESO	Alberta Electric System Operator
Agua Caliente	Agua Caliente Solar Project, a 290 MW photovoltaic power station located in Yuma County, Arizona in which NRG owned a 35% interest
ARO	Asset Retirement Obligation
ASC	The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU	Accounting Standards Updates - updates to the ASC
Average realized power prices	Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
BTU	British Thermal Unit
Business	NRG Business, which serves business customers
CAA	Clean Air Act
CAISO	California Independent System Operator
CARES Act	Coronavirus Aid, Relief, and Economic Security Act of 2020
CDD	Cooling Degree Day
CFTC	U.S. Commodity Futures Trading Commission
Centrica	Centrica plc
CO2	Carbon Dioxide
Company	NRG Energy, Inc.
Convertible Senior Notes	As of March 31, 2022, consists of NRG’s $575 million unsecured 2.75% Convertible Senior Notes due 2048
Cottonwood	Cottonwood Generating Station, a 1,177 MW natural gas-fueled plant
COVID-19	Coronavirus Disease 2019
CPP	Clean Power Plan
CPUC	California Public Utilities Commission
CWA	Clean Water Act
D.C. Circuit	U.S. Court of Appeals for the District of Columbia Circuit
Dth	Dekatherms
Economic gross margin	Sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuels and purchased energy and other cost of sales
EGU	Electric Generating Unit
EPA	U.S. Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESPP	NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
Exchange Act	The Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGD	Flue gas desulfurization
FTRs	Financial Transmission Rights
GAAP	Generally accepted accounting principles in the U.S.
GHG	Greenhouse Gas
Green Mountain Energy	Green Mountain Energy Company
GW	Gigawatts
GWh	Gigawatt Hour
HDD	Heating Degree Day

5

Heat Rate	A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending upon whether the electricity output measured is gross or net generation. Heat rates are generally expressed as BTU per net kWh
Home	NRG Home, which serves residential customers
HLW	High-level radioactive waste
ICE	Intercontinental Exchange
IESO	Independent Electricity System Operator
ISO	Independent System Operator, also referred to as RTOs
ISO-NE	ISO New England Inc.
Ivanpah	Ivanpah Solar Electric Generation Station, a 393 MW solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest
kWh	Kilowatt-hour
LaGen	Louisiana Generating, LLC
LTIPs	Collectively, the NRG long-term incentive plan ("LTIP") and the NRG GenOn LTIP
MDth	Thousand Dekatherms
Midwest Generation	Midwest Generation, LLC
MISO	Midcontinent Independent System Operator, Inc.
MMBtu	Million British Thermal Units
MW	Megawatts
MWh	Saleable megawatt hour net of internal/parasitic load megawatt-hour
NAAQS	National Ambient Air Quality Standards
NEPOOL	New England Power Pool
NERC	North American Electric Reliability Corporation
Net Exposure	Counterparty credit exposure to NRG, net of collateral
Net Revenue Rate	Sum of retail revenues less TDSP transportation charges
Nodal	Nodal Exchange is a derivatives exchange
NOL	Net Operating Loss
NOx	Nitrogen Oxides
NPNS	Normal Purchase Normal Sale
NRC	U.S. Nuclear Regulatory Commission
NRG	NRG Energy, Inc.
Nuclear Decommissioning Trust Fund	NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, Units 1 & 2
Nuclear Waste Policy Act	U.S. Nuclear Waste Policy Act of 1982
NYISO	New York Independent System Operator
NYMEX	New York Mercantile Exchange
OCI/OCL	Other Comprehensive Income/(Loss)
PJM	PJM Interconnection, LLC
PM2.5	Particulate Matter that has a diameter of less than 2.5 micrometers
PPA	Power Purchase Agreement
PUCT	Public Utility Commission of Texas
RCRA	Resource Conservation and Recovery Act of 1976
Receivables Facility	NRG Receivables LLC, a bankruptcy remote, special purpose, wholly-owned indirect subsidiary of the Company's $800 million accounts receivables securitization facility due 2022, which was amended on July 26, 2021
Receivables Securitization Facilities	Collectively, the Receivables Facility and the Repurchase Facility
Repurchase Facility	NRG's $150 million uncommitted repurchase facility related to the Receivables Facility due 2022, which was amended on July 26, 2021 and February 9, 2022
Revolving Credit Facility	The Company's $3.7 billion revolving credit facility due 2024, was amended on May 28, 2019 and August 20, 2020

6

RGGI	Regional Greenhouse Gas Initiative
RMR	Reliability Must-Run
RTO	Regional Transmission Organization, also referred to as ISOs
SEC	U.S. Securities and Exchange Commission
Securities Act	The Securities Act of 1933, as amended
Senior Notes	As of March 31, 2022, NRG's $4.6 billion outstanding unsecured senior notes consisting of $375 million of the 6.625% senior notes due 2027, $821 million of 5.75% senior notes due 2028, $733 million of the 5.25% senior notes due 2029, $500 million of the 3.375% senior notes due 2029, $1.0 billion of the 3.625% senior notes due 2031 and $1.1 billion of the 3.875% senior notes due 2032
Senior Secured First Lien Notes	As of March 31, 2022, NRG’s $2.5 billion outstanding Senior Secured First Lien Notes consists of $600 million of the 3.75% Senior Secured First Lien Notes due 2024, $500 million of the 2.0% Senior Secured First Lien Notes due 2025, $900 million of the 2.45% Senior Secured First Lien Notes due 2027 and $500 million of the 4.45% Senior Secured First Lien Notes due 2029
Services	NRG Services, which primarily includes the services businesses acquired in the Direct Energy Acquisition
SNF	Spent Nuclear Fuel
SO2	Sulfur Dioxide
SOFR	Secured overnight financing rate
South Central Portfolio	NRG's South Central Portfolio, which owned and operated a portfolio of generation assets consisting of Bayou Cove, Big Cajun-I, Big Cajun-II, Cottonwood and Sterlington, was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025
STP	South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC	South Texas Project Nuclear Operating Company
TDSP	Transmission/distribution service provider
U.S.	United States of America
U.S. DOE	U.S. Department of Energy
VaR	Value at Risk
VIE	Variable Interest Entity
Winter Storm Uri	A major winter and ice storm that had widespread impacts across North America occurring in February 2021

7

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended March 31,
(In millions, except for per share amounts)	2022		2021
Revenue
Revenue	$	7,896	$	8,091
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)	4,930		6,857
Depreciation and amortization	183		317
Selling, general and administrative costs	322		337
Provision for credit losses	25		611
Acquisition-related transaction and integration costs	8		42
Total operating costs and expenses	5,468		8,164
(Loss)/Gain on sale of assets	(3)		17
Operating Income/(Loss)	2,425		(56)
Other Income/(Expense)
Equity in (losses) of unconsolidated affiliates	(15)		(6)
Other income, net	—		22
Interest expense	(103)		(127)
Total other expense	(118)		(111)
Income/(Loss) Before Income Taxes	2,307		(167)
Income tax expense/(benefit)	571		(85)
Net Income/(Loss)	$	1,736	$	(82)
Income/(loss) per Share
Weighted average number of common shares outstanding — basic and diluted	242		245
Income/(loss) per Weighted Average Common Share —Basic and Diluted	$	7.17	$	(0.33)

See accompanying notes to condensed consolidated financial statements.

8

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)

	Three months ended March 31,
(In millions)	2022		2021
Net Income/(Loss)	$	1,736	$	(82)
Other Comprehensive Income
Foreign currency translation adjustments	9		3
Defined benefit plans	(1)		—
Other comprehensive income	8		3
Comprehensive Income/(Loss)	$	1,744	$	(79)

See accompanying notes to condensed consolidated financial statements.

9

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2022		December 31, 2021
(In millions, except share data)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	387	$	250
Funds deposited by counterparties	2,570		845
Restricted cash	39		15
Accounts receivable, net	3,291		3,245
Uplift securitization proceeds receivable from ERCOT	689		689
Inventory	354		498
Derivative instruments	9,089		4,613
Cash collateral paid in support of energy risk management activities	9		291
Prepayments and other current assets	409		395
Total current assets	16,837		10,841
Property, plant and equipment, net	1,643		1,688
Other Assets
Equity investments in affiliates	151		157
Operating lease right-of-use assets, net	256		271
Goodwill	1,796		1,795
Intangible assets, net	2,391		2,511
Nuclear decommissioning trust fund	949		1,008
Derivative instruments	3,561		2,527
Deferred income taxes	1,638		2,155
Other non-current assets	255		229
Total other assets	10,997		10,653
Total Assets	$	29,477	$	23,182
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and finance leases	$	4	$	4
Current portion of operating lease liabilities	82		81
Accounts payable	2,216		2,274
Derivative instruments	6,076		3,387
Cash collateral received in support of energy risk management activities	2,570		845
Accrued expenses and other current liabilities	1,285		1,324
Total current liabilities	12,233		7,915
Other Liabilities
Long-term debt and finance leases	8,026		7,966
Non-current operating lease liabilities	220		236
Nuclear decommissioning reserve	325		321
Nuclear decommissioning trust liability	602		666
Derivative instruments	1,977		1,412
Deferred income taxes	68		73
Other non-current liabilities	996		993
Total other liabilities	12,214		11,667
Total Liabilities	24,447		19,582
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,839,804 and 423,547,174 shares issued and 239,216,140 and 243,753,899 shares outstanding at March 31, 2022 and December 31, 2021, respectively	4		4
Additional paid-in-capital	8,433		8,531
Retained earnings	2,171		464
Treasury stock, at cost 184,623,664 and 179,793,275 shares at March 31, 2022 and December 31, 2021, respectively	(5,460)		(5,273)
Accumulated other comprehensive loss	(118)		(126)
Total Stockholders' Equity	5,030		3,600
Total Liabilities and Stockholders' Equity	$	29,477	$	23,182

See accompanying notes to condensed consolidated financial statements.

10

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended March 31,
(In millions)	2022		2021
Cash Flows from Operating Activities
Net Income/(Loss)	$	1,736	$	(82)
Adjustments to reconcile net income/(loss) to cash provided by operating activities:
Distributions from and equity in losses of unconsolidated affiliates	18		17
Depreciation and amortization	183		317
Accretion of asset retirement obligations	7		3
Provision for credit losses	25		611
Amortization of nuclear fuel	14		13
Amortization of financing costs and debt discounts	6		11
Amortization of in-the-money contracts and emissions allowances	147		7
Amortization of unearned equity compensation	6		4
Net gain on sale and disposal of assets	(6)		(18)
Changes in derivative instruments	(2,816)		(902)
Changes in deferred income taxes and liability for uncertain tax benefits	527		(71)
Changes in collateral deposits in support of energy risk management activities	2,007		1
Changes in nuclear decommissioning trust liability	(7)		15
Changes in other working capital	(171)		(843)
Cash provided/(used) by operating activities	1,676		(917)
Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets, net of cash acquired	(26)		(3,482)
Capital expenditures	(60)		(63)
Net purchases of emission allowances	(18)		(5)
Investments in nuclear decommissioning trust fund securities	(151)		(129)
Proceeds from the sale of nuclear decommissioning trust fund securities	161		118
Proceeds from sale of assets, net of cash disposed	14		197
Cash used by investing activities	(80)		(3,364)
Cash Flows from Financing Activities
Payments of dividends to common stockholders	(85)		(80)
Payments for share repurchase activity	(188)		(9)
Net receipts from settlement of acquired derivatives that include financing elements	561		190
Net proceeds of Revolving Credit Facility and Receivables Securitization Facilities	—		825
Repayments of long-term debt and finance leases	(1)		(1)
Payments of debt issuance costs	—		(2)
Proceeds from issuance of common stock	—		1
Cash provided by financing activities	287		924
Effect of exchange rate changes on cash and cash equivalents	3		1
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	1,886		(3,356)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,110		3,930
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	2,996	$	574

See accompanying notes to condensed consolidated financial statements.

11

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

(In millions)	Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2021	$	4	$	8,531	$	464	$	(5,273)	$	(126)	$	3,600
Net income					1,736						1,736
Other comprehensive income									8		8
Share repurchases							(187)				(187)
Equity-based awards activity, net(a)			2								2
Common stock dividends and dividend equivalents declared(b)					(86)						(86)
Adoption of ASU 2020-06			(100)		57						(43)
Balance at March 31, 2022	$	4	$	8,433	$	2,171	$	(5,460)	$	(118)	$	5,030

(In millions)	Common Stock		Additional Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2020	$	4	$	8,517	$	(1,403)	$	(5,232)	$	(206)	$	1,680
Net loss					(82)						(82)
Other comprehensive income									3		3
Equity-based awards activity, net(a)			(5)								(5)
Issuance of common stock			1								1
Common stock dividends and dividend equivalents declared(b)					(80)						(80)
Balance at March 31, 2021	$	4	$	8,513	$	(1,565)	$	(5,232)	$	(203)	$	1,517

(a)Includes $(6) million and $(9) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended March 31, 2022 and 2021, respectively

(b)Dividends per common share were $0.35 and $0.325 for the quarters ended March 31, 2022 and 2021, respectively

See accompanying notes to condensed consolidated financial statements.

12

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Nature of Business and Basis of Presentation

General

NRG Energy, Inc., or NRG or the Company, is a consumer services company built on dynamic retail brands. NRG brings the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. NRG sells power, natural gas, home and power services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy. The Company has a customer base that includes approximately 6 million Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of generation.

During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released, leading the Company to announce the near-term retirement of approximately 1,600 MW of its PJM coal generating assets in June 2022. On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of those assets, Indian River Unit 4. On August 27, 2021 the Company notified PJM that it would continue operations at Indian River Unit 4 until the reliability upgrades identified by PJM were completed, provided that the unit receives a satisfactory and compensatory reliability must run arrangement. Accordingly, NRG filed a cost based RMR rate schedule at FERC on April 1, 2022, seeking a June 1, 2022 effective date. The Company is continuing to evaluate the viability of the remaining PJM generating assets.

The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus.

The Company's business is segmented as follows:

•Texas, which includes all activity related to customer, plant and market operations in Texas, other than Cottonwood;

•East, which includes all activity related to customer, plant and market operations in the East;

•West/Services/Other, which includes the following assets and activities: (i) all activity related to plant and market operations in the West and Canada, (ii) the Services businesses (iii) activity related to the Cottonwood facility, (iv) the remaining renewables activity, including the Company’s equity method investment in Ivanpah Master Holdings, LLC, and (v) activity related to the Company’s equity method investment for the Gladstone power plant in Australia; and

•Corporate activities.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's 2021 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of March 31, 2022, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three months ended March 31, 2022 and 2021.

Use of Estimates

The preparation of financial statements in conformity with GAAP 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.

Reclassifications

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

13

Note 2 — Summary of Significant Accounting Policies

Other Balance Sheet Information

The following table presents the accumulated depreciation included in property, plant and equipment, net and accumulated amortization included in intangible assets, net:

(In millions)	March 31, 2022		December 31, 2021
Property, plant and equipment accumulated depreciation	$	1,419	$	1,308
Intangible assets accumulated amortization	1,867		1,636

Credit Losses

Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues a provision 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 following table represents the activity in the allowance for credit losses for the three months ended March 31, 2022 and 2021:

	Three months ended March 31,
(In millions)	2022		2021
Beginning balance	$	683	$	67
Acquired balance from Direct Energy	—		112
Provision for credit losses	25		611
Write-offs	(50)		(48)
Recoveries collected	8		7
Ending balance	$	666	$	749

The decrease in the provision for credit losses during the three months ended March 31, 2022, compared to the same period in 2021 was primarily due to the impacts of Winter Storm Uri during the prior year on bilateral finance hedging risk of $393 million, counterparty credit risk of $109 million and ERCOT default shortfall payments of $83 million.

Cash and Cash Equivalents, Funds Deposited by Counterparties and 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:

(In millions)	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	387	$	250
Funds deposited by counterparties	2,570		845
Restricted cash	39		15
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	2,996	$	1,110

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties related to NRG's hedging program. The increase in funds deposited by counterparties is driven by the significant increase in forward positions as a result of increases in natural gas and power prices. Though some amounts are segregated into separate accounts, not all funds are contractually restricted. Based on the Company's intention, these funds are not available for the payment of general corporate obligations; however, they are available for liquidity management. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the 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.

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

14

Winter Storm Uri Uplift Securitization Proceeds

The Texas Legislature passed House Bill ("HB") 4492 in May of 2021 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.

In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement methodology. The Company accounted for the proceeds it will receive by analogy to the contribution model within ASC 958-605, Not-for-Profit Entities- Revenue Recognition and the grant model within IAS 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to cost of operations within its consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company expects to receive proceeds of $689 million from ERCOT in the second quarter of 2022 which is reflected as a receivable on its consolidated balance sheets.

Recent Accounting Developments - Guidance Adopted in 2022

ASU 2020-06 — In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40), or ASU 2020-06. The guidance in ASU 2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock. In addition, ASU 2020-06 improves and amends the related earnings per share guidance. The Company adopted this standard on January 1, 2022 using the modified retrospective approach. As a result of the provisions of the amended guidance, the Company recorded a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings and a $14 million decrease to long-term deferred tax liabilities. The adoption of ASU 2020-06 did not have a material impact on the Company's statement of operations, statement of cash flow or earnings per share amounts.

Note 3 — Revenue Recognition

Performance Obligations

As of March 31, 2022, estimated future fixed fee performance obligations are $151 million for the remaining nine months of fiscal year 2022, and $52 million and $1 million for the fiscal years 2023 and 2024, respectively. These performance obligations are for cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non-performance.

15

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three months ended March 31, 2022 and 2021:

	Three months ended March 31, 2022
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,289	$	675	$	697	$	—	$	2,661
Business	663		3,846		400		—		4,909
Total retail revenue	1,952		4,521		1,097		—		7,570
Energy revenue(b)	15		204		54		5		278
Capacity revenue(b)	—		115		1		—		116
Mark-to-market for economic hedging activities(c)	(2)		(130)		(18)		17		(133)
Contract amortization	—		(9)		—		—		(9)
Other revenue(b)	58		17		4		(5)		74
Total revenue	2,023		4,718		1,138		17		7,896
Less: Revenues accounted for under topics other than 606 and 815	—		(9)		11		—		2
Less: Realized and unrealized ASC 815 revenue	(7)		(66)		(42)		20		(95)
Total revenue from contracts with customers	$	2,030	$	4,793	$	1,169	$	(3)	$	7,989
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	45	$	(20)	$	4	$	29
Capacity revenue	—		13		—		—		13
Other revenue	(5)		6		(4)		(1)		(4)
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

	Three months ended March 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,333	$	584	$	554	$	—	$	2,471
Business	781		2,629		281		—		3,691
Total retail revenue	2,114		3,213		835		—		6,162
Energy revenue(c)	285		126		70		1		482
Capacity revenue(c)	—		141		14		—		155
Mark-to-market for economic hedging activities(d)	(1)		(4)		(28)		1		(32)
Other revenue(b)(c)	1,304		19		4		(3)		1,324
Total revenue	3,702		3,495		895		(1)		8,091
Less: Revenues accounted for under topics other than 606 and 815	—		—		2		—		2
Less: Realized and unrealized ASC 815 revenue	93		99		(34)		2		160
Total revenue from contracts with customers	$	3,609	$	3,396	$	927	$	(3)	$	7,929
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.2 billion driven by high pricing during Winter Storm Uri
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	60	$	(4)	$	2	$	58
Capacity revenue	—		37		—		—		37
Other revenue	94		6		(2)		(1)		97
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

16

Contract Balances

The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of March 31, 2022 and December 31, 2021:

(In millions)	March 31, 2022		December 31, 2021
Deferred customer acquisition costs	$	111	$	133
Accounts receivable, net - Contracts with customers	3,091		3,057
Accounts receivable, net - Derivative instruments	197		182
Accounts receivable, net - Affiliate	3		6
Total accounts receivable, net	$	3,291	$	3,245
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,237	$	1,574
Deferred revenues(a)	177		227

(a) Deferred revenues from contracts with customers for the three months ended March 31, 2022 and the year ended December 31, 2021 were approximately $169 million and $224 million, respectively

The revenue recognized from contracts with customers during the three months ended March 31, 2022 and 2021 relating to the deferred revenue balance at the beginning of each period was $117 million and $23 million, respectively. The change in deferred revenue balances during the three months ended March 31, 2022 and 2021 was primarily due to the usage of customer bill credits by certain C&I customers, which were as a result of power pricing during Winter Storm Uri and a significant increase in customer count as a result of the Direct Energy acquisition.

Note 4 — Acquisitions and Dispositions

Acquisitions

2021 Acquisition of Direct Energy

On January 5, 2021, the Company acquired all of the issued and outstanding common shares of Direct Energy, which had been a North American subsidiary of Centrica. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition 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 and total purchase price adjustment of $99 million, resulting in an adjusted purchase price of $3.724 billion. For additional information refer to Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Company's 2021 Form 10-K.

Dispositions

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

Note 5 — Fair Value of Financial Instruments

For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts payable, and cash collateral paid and received in support of energy risk management activities, the carrying amounts approximate fair values because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

17

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

	March 31, 2022				December 31, 2021
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Convertible Senior Notes	$	575	$	633	$	518	$	677
Other long-term debt, including current portion	7,523		7,128		7,522		7,650
Total long-term debt, including current portion(a)	$	8,098	$	7,761	$	8,040	$	8,327

(a) Excludes deferred financing costs, which are recorded as a reduction to long-term debt in 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.

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 condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:

	March 31, 2022
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	17	$	—	$	17	$	—
Nuclear trust fund investments:
Cash and cash equivalents	17		17		—		—
U.S. government and federal agency obligations	106		105		1		—
Federal agency mortgage-backed securities	104		—		104		—
Commercial mortgage-backed securities	41		—		41		—
Corporate debt securities	116		—		116		—
Equity securities	471		471		—		—
Foreign government fixed income securities	2		—		2		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	12,650		2,528		9,403		719
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	92
Equity securities (classified within other non-current assets)	7
Total assets	$	13,624	$	3,122	$	9,684	$	719
Derivative liabilities:
Foreign exchange contracts	$	4	$	—	$	4	$	—
Commodity contracts	8,049		1,173		6,685		191
Total liabilities	$	8,053	$	1,173	$	6,689	$	191

18

	December 31, 2021
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	32	$	15	$	17	$	—
Nuclear trust fund investments:
Cash and cash equivalents	33		33		—		—
U.S. government and federal agency obligations	112		111		1		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	44		—		44		—
Corporate debt securities	122		—		122		—
Equity securities	494		494		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Foreign exchange contracts	1		—		1		—
Commodity contracts	7,139		981		5,701		457
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	99
Equity securities (classified within other non-current assets)	7
Total assets	$	8,188	$	1,635	$	5,990	$	457
Derivative liabilities:
Foreign exchange contracts	$	1	$	—	$	1	$	—
Commodity contracts	4,798		626		4,008		164
Total liabilities	$	4,799	$	626	$	4,009	$	164

The following table reconciles, for the three months ended March 31, 2022 and 2021, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs:

	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Derivatives(a)
(In millions)	Three months ended March 31, 2022		Three months ended March 31, 2021
Beginning balance	$	293	$	(16)
Contracts added from Direct Energy acquisition	—		(15)
Total gains realized/unrealized — included in earnings	166		180
Purchases	23		20
Transfers into Level 3(b)	53		4
Transfers out of Level 3(b)	(7)		(14)
Ending balance	$	528	$	159
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 period end	$	237	$	146

(a)Consists of derivative 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 in/out are with Level 2

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

19

Derivative Fair Value Measurements

A portion of NRG'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. The remainder of the assets and liabilities represent 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 the observable market data with similar characteristics. As of March 31, 2022, contracts valued with prices provided by models and other valuation techniques make up 6% of derivative assets and 2% of derivative liabilities.

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

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of March 31, 2022 and December 31, 2021:

	March 31, 2022
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	$	676	$	153	Discounted Cash Flow	Forward Market Price (per MWh)	$	6	$	278	$	47
FTRs	43		38		Discounted Cash Flow	Auction Prices (per MWh)	(105)		43		0
	$	719	$	191

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

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of March 31, 2022 and December 31, 2021:

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

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 is calculated based on published default probabilities. As of March 31, 2022, the credit reserve resulted in a $5 million decrease primarily within cost of operations. As of December 31, 2021, the credit reserve resulted in a $11 million decrease primarily within cost of operations.

20

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2021 Form 10-K, the following is a discussion of the concentration of credit risk for the Company's contractual obligations. 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. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, as well as retail customer credit risk through its retail load activities.

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2021 Form 10-K. As of March 31, 2022, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $3.2 billion and NRG held collateral (cash and letters of credit) against those positions of $1.5 billion, resulting in a net exposure of $1.8 billion. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 82% of the Company's exposure before collateral is expected to roll off by the end of 2023. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.

	Net Exposure(a)(b)
Category by Industry Sector	(% of Total)
Utilities, energy merchants, marketers and other	59	%
Financial institutions	41
Total as of March 31, 2022	100	%

	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	59	%
Non-investment grade/non-rated	41
Total as of March 31, 2022	100	%

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

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

The Company currently has no exposure to wholesale counterparties in excess of 10% of total net exposure discussed above as of March 31, 2022. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

During the first quarter of 2021, during Winter Storm Uri, the Company experienced a nonperformance by a counterparty in one of its bilateral financial hedging transactions, resulting in exposure of $393 million. The Company is pursuing all means available to enforce its obligations under this transaction but, given the size of the exposure and the counterparty filing for Chapter 11 bankruptcy protection, cannot determine with certainty what the amount of its ultimate recovery will be. The full exposure was recorded as a provision for credit losses as of March 31, 2021.

RTOs and ISOs

The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, whereas in the case of ERCOT, it is approved by the PUCT, and whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO to the Ontario Energy Board. These ISOs may include 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 the overall market and are excluded from the above exposures.

21

Exchange Traded Transactions

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

Long-Term Contracts

Counterparty credit exposure described above excludes credit risk exposure under certain long-term contracts, primarily solar PPAs. As external sources or observable market quotes are not always 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 March 31, 2022, aggregate credit risk exposure managed by NRG to these counterparties was approximately $1.2 billion for the next five years.

Retail Customer Credit Risk

The Company is exposed to retail credit risk through the Company's retail electricity and gas providers, which serve Home and Business customers. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both non-payment 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 March 31, 2022, the Company's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. 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.

Note 6 — Nuclear Decommissioning Trust Fund

NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its 44% interest in STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, 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 OCI, 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 March 31, 2022							As of December 31, 2021
(In millions, except maturities)	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	$	17	$	—	$	—	—	$	33	$	—	$	—	—
U.S. government and federal agency obligations	106		2		4		10	112		5		1		10
Federal agency mortgage-backed securities	104		1		3		25	100		2		—		25
Commercial mortgage-backed securities	41		—		2		27	44		1		—		27
Corporate debt securities	116		2		5		14	122		7		1		14
Equity securities	563		424		—		—	593		456		—		—
Foreign government fixed income securities	2		—		—		19	4		—		—		13
Total	$	949	$	429	$	14		$	1,008	$	471	$	2

22

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

	Three months ended March 31,
(In millions)	2022		2021
Realized gains	$	1	$	3
Realized losses	(4)		(2)
Proceeds from sale of securities	161		118

Note 7 — Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of March 31, 2022, NRG had energy-related derivative instruments extending through 2036. The Company marks these derivatives to market through the statement of operations. NRG has executed energy-related contracts extending through 2038 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

Foreign Exchange Contracts

NRG is exposed to changes in foreign currency primarily associated with the purchase of USD denominated natural gas for its Canadian business. In order to manage the Company's foreign exchange risk, NRG entered into foreign exchange contracts. As of March 31, 2022, NRG had foreign exchange contracts extending through 2025. The Company marks these derivatives to market through the statement of operations.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of March 31, 2022 and December 31, 2021. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.

		Total Volume (In millions)
Category	Units	March 31, 2022		December 31, 2021
Emissions	Short Ton	—		1
Renewable Energy Certificates	Certificates	13		13
Coal	Short Ton	14		19
Natural Gas	MMBtu	811		813
Oil	Barrels	—		1
Power	MWh	175		185
Foreign Exchange	Dollars	$	264	$	279

Fair Value of Derivative Instruments

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

	Fair Value
	Derivative Assets				Derivative Liabilities
(In millions)	March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Foreign exchange contracts - current	$	—	$	—	$	2	$	1
Foreign exchange contracts - long-term	—		1		2		—
Commodity contracts - current	9,089		4,613		6,074		3,386
Commodity contracts - long-term	3,561		2,526		1,975		1,412
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	12,650	$	7,140	$	8,053	$	4,799

23

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 of 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 March 31, 2022
Foreign exchange contracts:
Derivative liabilities	$	(4)	$	—	$	—	$	(4)
Commodity contracts:
Derivative assets	$	12,650	$	(7,482)	$	(2,631)	$	2,537
Derivative liabilities	(8,049)		7,482		41		(526)
Total commodity contracts	$	4,601	$	—	$	(2,590)	$	2,011
Total derivative instruments	$	4,597	$	—	$	(2,590)	$	2,007

	Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
As of December 31, 2021
Foreign exchange contracts:
Derivative assets	$	1	$	(1)	$	—	$	—
Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	$	—	$	—	$	—	$	—
Commodity contracts:
Derivative assets	$	7,139	$	(4,440)	$	(831)	$	1,868
Derivative liabilities	(4,798)		4,440		17		(341)
Total commodity contracts	$	2,341	$	—	$	(814)	$	1,527
Total derivative instruments	$	2,341	$	—	$	(814)	$	1,527

24

Impact of Derivative Instruments on the Statements of Operations

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

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

(In millions)	Three months ended March 31,
Unrealized mark-to-market results	2022		2021
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(408)	$	17
Reversal of acquired (gain)/loss positions related to economic hedges	(60)		145
Net unrealized gains on open positions related to economic hedges	2,745		559
Total unrealized mark-to-market gains for economic hedging activities	2,277		721
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	1		(7)
Net unrealized (losses)/gains on open positions related to trading activity	(15)		11
Total unrealized mark-to-market (losses)/gains for trading activity	(14)		4
Total unrealized gains	$	2,263	$	725

	Three months ended March 31,
(In millions)	2022		2021
Unrealized (losses) included in revenues - commodities	$	(147)	$	(28)
Unrealized gains included in cost of operations - commodities	2,414		755
Unrealized (losses) included in cost of operations - foreign exchange	(4)		(2)
Total impact to statement of operations - commodities	$	2,263	$	725

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

For the three months ended March 31, 2022, the $2.7 billion unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward positions as a result of increases in natural gas and power prices.

For the three months ended March 31, 2021, the $559 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward positions due to increases in ERCOT power prices and ERCOT heat rate expansion.

Credit Risk Related Contingent Features

Certain of the Company's trading agreements contain provisions that entitle the counterparty to demand that the Company post additional collateral if the counterparty determines that there has been deterioration in the Company's credit quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if there were a downgrade in the Company's credit rating. The collateral potentially required for all contracts with adequate assurance clauses that are in a net liability position as of March 31, 2022 was $790 million. The Company is also party to certain marginable agreements under which it has net liability position, but the counterparty has not called for the collateral due, which was approximately $56 million as of March 31, 2022. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $26 million of additional collateral would be required for all contracts with credit rating contingent features as of March 31, 2022.

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

25

Note 8 — Long-term Debt and Finance Leases

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

(In millions, except rates)	March 31, 2022		December 31, 2021		Interest rate %
Recourse debt:
Senior Notes, due 2027	$	375	$	375	6.625
Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	733		733		5.250
Senior Notes, due 2029	500		500		3.375
Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	1,100		1,100		3.875
Convertible Senior Notes, due 2048(a)	575		575		2.750
Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2025	500		500		2.000
Senior Secured First Lien Notes, due 2027	900		900		2.450
Senior Secured First Lien Notes, due 2029	500		500		4.450
Tax-exempt bonds	466		466		1.250 - 4.750
Subtotal recourse debt	8,100		8,100
Finance leases	13		13		various
Subtotal long-term debt and finance leases (including current maturities)	8,113		8,113
Less current maturities	(4)		(4)
Less debt issuance costs	(81)		(83)
Discounts	(2)		(60)
Total long-term debt and finance leases	$	8,026	$	7,966

(a)As of the ex-dividend date of April 29, 2022, the Convertible Senior Notes were convertible at a price of 44.15, which is equivalent to a conversion rate of approximately 22.6516 shares of common stock per $1,000 principal amount.

2048 Convertible Senior Notes

Accounting for Convertible Senior Notes — Upon issuance, the Convertible Senior Notes were separated into liability and equity components for accounting purposes. The carrying amounts of the liability component was initially calculated by measuring the fair value of similar liabilities that do not have an associated convertible feature. The carrying amount of the equity component representing the conversion option was determined by deducting the fair value of the liability component from the par value of the Convertible Senior Notes. This difference represented the debt discount that was amortized to interest expense over seven years, which was determined to be the expected life of the Convertible Senior Notes, using the effective interest rate method. The equity component was recorded in additional paid-in capital and was not remeasured as it continued to meet the conditions for equity classification.

Following the adoption of ASU 2020-06 as of January 1, 2022, the Company no longer records the conversion feature of its convertible senior notes in equity. Instead, the Company combined the previously separated equity component with the liability component, which together is now classified as debt, thereby eliminating the subsequent amortization of the debt discount as interest expense. As a result of the provisions of the amended guidance, the Company recorded a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings and a $14 million decrease to long-term deferred tax liabilities. For more information on the adoption of ASU 2020-06, refer to Note 2, Summary of Significant Accounting Policies.

Modification to Convertible Senior Notes — On February 22, 2022, the Company irrevocably elected to eliminate the right to settle conversions only in shares of the Company's common stock, such that any conversion after such date, the Company will pay cash per $1,000 principal amount and will settle in cash or a combination of cash and the Company's common stock for the remainder, if any, of the Company’s conversion obligation in excess of the aggregate principal amount.

Convertible Senior Notes Features — As of March 31, 2022, the Convertible Senior Notes were convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock at a price of $44.53 per common share, which is equivalent to a conversion rate of approximately 22.4563 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The Convertible Senior Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The Convertible Senior notes are convertible at the option of the holders under certain circumstances. Prior to the close of business on the business day immediately preceding December 1, 2024, the Convertible

26

Senior Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:

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

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

The following table details the interest expense recorded in connection with the Convertible Senior Notes, due 2048:

($ In millions)	For the three months ended March 31, 2022			For the three months ended March 31, 2021
Contractual interest expense	$	4		$	4
Amortization of discount and deferred finance costs	—			4
Total	$	4		$	8
Effective Interest Rate	0.76		%	1.32		%

Repurchase Facility

On February 9, 2022, the Company entered into amendments to its existing Repurchase Facility to, among other things, (i) increase the size of the facility from $75 million to $150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate. The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%. As of March 31, 2022, there were no outstanding borrowings.

Bilateral Letter of Credit Facilities

On April 29, 2022, the Company increased the size of the facilities by $100 million to provide additional liquidity, allowing for the issuance of up to $575 million of letters of credit.

Note 9 — Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs

Entities that are not Consolidated

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

Variable Interest Entities that are Consolidated

The Company has a controlling financial interest that has been identified as a VIE under ASC 810 in NRG Receivables LLC, which has entered into financing transactions related to the Receivables Facility as further described in Note 13, Long-term Debt and Finance Leases, to the Company’s 2021 Form 10-K.

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

(In millions)	March 31, 2022		December 31, 2021
Accounts receivable and Other current assets	$	573	$	939
Current liabilities	78		78
Net assets	$	495	$	861

27

Note 10 — Changes in Capital Structure

As of March 31, 2022 and December 31, 2021, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:

	Issued	Treasury	Outstanding
Balance as of December 31, 2021	423,547,174	(179,793,275)	243,753,899
Shares issued under LTIPs	292,630	—	292,630
Shares repurchased	—	(4,830,389)	(4,830,389)
Balance as of March 31, 2022	423,839,804	(184,623,664)	239,216,140
Shares issued under LTIPs	13,213	—	13,213
Shares issued under ESPP	—	68,941	68,941
Shares repurchased	—	(2,014,734)	(2,014,734)
Balance as of April 30, 2022	423,853,017	(186,569,457)	237,283,560

Share Repurchases

The Company adopted in the fourth quarter of 2019 a long-term capital allocation policy that targets allocating 50% of cash available for allocation generated each year to growth investments and 50% to be returned to shareholders. The return of capital to shareholders is expected to be completed through the increased dividend discussed below, supplemented by share repurchases. On December 6, 2021 the Company announced that the Board of Directors has authorized $1 billion for share repurchases, as part of NRG’s capital allocation program. During 2021, $44 million of share repurchases were completed under this authorization. During the first quarter of 2022, the Company completed $187 million of share repurchases under the plan at an average price of $38.66.

The following repurchases have been made during the three months ended March 31, 2022 and through April 30, 2022:

	Total number of shares and share equivalents purchased	Average price paid per share and share equivalent	Amounts paid for shares and share equivalents purchased (in millions)
2022 repurchases
Repurchases(a)	4,830,389		$	187
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	131,899		6
Total Share Repurchases during the three months ended March 31, 2022	4,962,288	$38.78	193
Repurchases made during April 2022	2,014,734		$	76
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	5,465		—
Total Share Repurchases January 1, 2022 through April 30, 2022	6,982,487	$38.55	$	269

(a)Includes $10 million accrued as of March 31, 2022

(b)NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management. The average price per equivalent shares withheld was $43.03 and $39.19 for the three months ended March 31, 2022 and for April 2022, respectively

Employee Stock Purchase Plan

In March 2019, the Company reopened participation in the ESPP, which allows eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of NRG common stock at the lesser of 95% of its market value on the offering date or 95% of the fair market value on the exercise date. An offering date occurs each April 1 and October 1. An exercise date occurs each September 30 and March 31.

NRG Common Stock Dividends

During the first quarter of 2022, NRG increased the annual dividend to $1.40 from $1.30 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.35 per share was paid on the Company's common stock during the three months ended March 31, 2022. On April 20, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, payable on May 16, 2022 to stockholders of record as of May 2, 2022.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

28

Note 11 — Income/(loss) Per Share

Basic income/(loss) per common share is computed by dividing net income/(loss) by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted income per share is computed in a manner consistent with that of basic income per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The outstanding relative performance stock units, non-vested restricted stock units, market stock units, and non-qualified stock options are not considered outstanding for purposes of computing basic income per share. However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method for periods when we have net income. The Convertible Senior Notes are convertible, under certain circumstances, into cash or combination of cash and Company’s common stock. Prior to adoption of ASU 2020-06, there was no dilutive effect for the Convertible Senior Notes due to the Company’s expectation to settle the liability in cash. Upon adoption of ASU 2020-06, on January 1, 2022, the Company is including the potential share settlements, if any, in the denominator for purposes of computing diluted income per share under the if converted method for periods when we have net income. The potential shares settlements are calculated as the excess of the Company's conversion obligation over the aggregate principal amount (which will be settled in cash), divided by the average share price for the period. For the period ended March 31, 2022, there was no dilutive effect for the Convertible Senior Notes since there were no potential share settlements for that period.

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

	Three months ended March 31,
(In millions, except per share data)	2022		2021
Basic income/(loss) per share:
Net income/(loss)	$	1,736	$	(82)
Weighted average number of common shares outstanding - basic	242		245
Income/(loss) per weighted average common share — basic	$	7.17	$	(0.33)
Diluted income/(loss) per share:
Net income/(loss)	$	1,736	$	(82)
Weighted average number of common shares outstanding - basic	242		245
Weighted average number of common shares outstanding - dilutive	242		245
Income/(loss) per weighted average common share — diluted	$	7.17	$	(0.33)

As of March 31, 2022, the Company had 1 million outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted income per share. As of March 31, 2021, the Company had 1 million shares of outstanding equity instruments that were not included in the computation of the Company’s diluted loss per share since the Company was in a loss position for the period.

Note 12 — Segment Reporting

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

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and allocation of capital, as well as net income/(loss).

	Three months ended March 31, 2022
(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Revenue	$	2,023	$	4,718	$	1,138	$	—	$	17	$	7,896
Depreciation and amortization	76		78		21		8		—		183
Loss on sale of assets	—		—		(1)		(2)		—		(3)
Equity in (losses) of unconsolidated affiliates	(1)		—		(14)		—		—		(15)
Income/(loss) before income taxes	773		1,541		124		(131)		—		2,307
Net income/(loss)	$	773	$	1,541	$	125	$	(703)	$	—	$	1,736

29

	Three months ended March 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Revenue	$	3,702	$	3,495	$	895	$	—	$	(1)	$	8,091
Depreciation and amortization	77		206		27		7		—		317
Gain on sale of assets	—		—		17		—		—		17
Equity in (losses) of unconsolidated affiliates	(1)		—		(5)		—		—		(6)
(Loss)/income before income taxes	(433)		356		79		(169)		—		(167)
Net (loss)/income	$	(433)	$	356	$	74	$	(79)	$	—	$	(82)

Note 13 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:

	Three months ended March 31,
(In millions, except rates)	2022			2021
Income before income taxes	$	2,307		$	(167)
Income tax expense/(benefit)	571			(85)
Effective income tax rate	24.8		%	50.9		%

For the three months ended March 31, 2022, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense. For the same periods in 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax benefits and one-time tax benefits, as a result of the acquisition of Direct Energy, on the revaluation of state deferred tax assets, NOLs, and valuation allowance.

Uncertain Tax Benefits

As of March 31, 2022, NRG had a non-current tax liability of $19 million for uncertain tax benefits from positions taken on various federal and state income tax returns and accrued interest. For the three months ended March 31, 2022, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of March 31, 2022, NRG had cumulative interest and penalties related to these uncertain tax benefits of $1 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia and Canada. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2017. With few exceptions, state and local income tax examinations are no longer open for years prior to 2013.

Note 14 — Related Party Transactions

NRG provides services to some of its related parties, who are accounted for as equity method investments, under operations and maintenance agreements. Fees for the services under these agreements include recovery of NRG's costs of operating the plants. Certain agreements also include fees for administrative service, a base monthly fee, profit margin and/or annual incentive bonus.

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

	Three months ended March 31,
(In millions)	2022		2021
Revenues from Related Parties Included in Revenue
Gladstone	$	1	$	1
Ivanpah(a)	13		12
Midway-Sunset	2		2
Total	$	16	$	15

(a)Also includes fees under project management agreements with each project company

30

Note 15 — Commitments and Contingencies

Commitments

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of property and assets owned by NRG and the guarantors of its senior debt. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedges. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a claim under the first lien program. As of March 31, 2022, hedges under the first lien program were out-of-the-money for NRG on a counterparty aggregate basis.

Contingencies

The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records accruals for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, the Company has established an adequate accrual for the applicable legal matters, including regulatory and environmental matters as further discussed in Note 16, Regulatory Matters, and Note 17, Environmental Matters. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded accruals and that such differences could be material.

In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

Environmental Lawsuits

Sierra club et al. v. Midwest Generation LLC — In 2012, several environmental groups filed a complaint against Midwest Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in groundwater contamination. In June 2019, the IPCB found in an interim order that Midwest Generation violated the law because it had improperly handled coal ash at four facilities in Illinois and caused or allowed coal ash constituents to impact groundwater. On September 9, 2019, Midwest Generation filed a Motion to Reconsider numerous issues, which the court granted in part and denied in part on February 6, 2020. The IPCB will hold hearings to determine the appropriate relief. Midwest Generation has been working with the Illinois EPA to address the groundwater issues since 2010.

Consumer Lawsuits

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

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

XOOM Energy

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

Direct Energy

There are three putative class actions pending against Direct Energy: (1) Linda Stanley v. Direct Energy (S.D.N.Y Apr. 2019) - The parties mediated in June and agreed on a settlement. On November 16, 2021, the Court granted preliminary approval of the settlement. On April 5, 2022, the Court granted final approval of the settlement. However, it may take several months to determine the final payout amount; (2) Martin Forte v. Direct Energy (N.D.N.Y. Mar. 2017) - The Court recently granted Direct Energy's Motion for summary judgment effectively ending the matter at the district court level. It is likely that the plaintiff will appeal; however, it is unlikely the plaintiff will prevail; (3) Richard Schafer v. Direct Energy (W.D.N.Y. Dec.

31

2019; on appeal 2nd Cir. N.Y.) - The Court granted limited discovery that will end April 29, 2022. Summary judgment briefing is due on May 20, 2022.

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

There are two putative class actions pending against Direct Energy: (1) Holly Newman v. Direct Energy, LP (D. Md Sept 2021) - Direct Energy filed its Motion to Dismiss asserting the ruling in the Brittany Burk v. Direct Energy (S.D. Tex. Feb 2019) preempts the Plaintiff's ability to file suit based on the same facts; and (2) Matthew Dickson v. Direct Energy (N.D. Ohio Jan. 2018) - Direct Energy filed a Third-Party Petition against its vendor, Total Marketing Concepts, LLC, who placed voicemails without consent from Direct Energy and in violation of the parties’ agreement. The case was stayed pending the outcome of an appeal to the Sixth Circuit based on the unconstitutionality of the TCPA during the period from 2015-2020. The Sixth Circuit found the TCPA was in effect during that period and remanded the case back to the trial court. Direct Energy refiled its motions along with supplements. On March 25, 2022, the Court granted summary judgment in favor of Direct Energy and dismissed the case. The plaintiff is expected to appeal.

Winter Storm Uri Lawsuits

The Company has been named in certain property damage and wrongful death claims that have been filed in connection with Winter Storm Uri in its capacity as a generator and a retail electric provider. As a power generator, the Company is named in 161 cases with claims ranging from: wrongful death; personal injury only; property damage and personal injury; property damage only; and subrogation. As a retail electric provider, the Company is named in 27 lawsuits with similar claims: wrongful death; property damage only; personal injury only; and both personal injury and property damage. The power generators and retail electric providers are working together to file a handful of motions to dismiss that represent the breadth of the claims filed against them. These motions are due May 17, 2022. All of the lawsuits related to Winter Storm Uri are consolidated into a single multi-district litigation matter in Harris County District Court. The Company intends to vigorously defend these matters.

Indemnifications and Other Contractual Arrangements

Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against LaGen in the United States District Court for the Middle District of Louisiana. The plaintiffs claimed breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs sought damages for the alleged improper charges and a declaration as to which charges were proper under the contract. In February 2020, the court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. On March 17, 2020, plaintiffs filed a lawsuit in the Nineteenth Judicial District Court for the Parish of East Baton Rouge in Louisiana alleging substantially the same matters. On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.

Note 16 — Regulatory Matters

Environmental regulatory matters are discussed within Note 17, Environmental Matters.

NRG operates in a highly regulated industry and is subject to regulation by various federal, state and provincial agencies. As such, NRG is affected by regulatory developments at the federal, state and provincial levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail operations.

In addition to the regulatory proceeding noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

California Station Power — As the result of unfavorable final and non-appealable litigation, the Company accrued a liability associated with consumption of station power at the Company's Encina power plant facility in California after August 30, 2010. The Company has established an appropriate accrual pending potential regulatory action by San Diego Gas & Electric regarding the Company's Encina facility.

32

Note 17 — Environmental Matters

NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. The electric generation industry has been facing increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose additional restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. The Company has elected to use a $1 million disclosure threshold, as permitted, for environmental proceedings to which the government is a party.

Air

On July 8, 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. The ACE rule required states that have coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). On October 29, 2021, the U.S. Supreme Court agreed to review the D.C. Circuit's decision, which should provide some clarity regarding the scope of the EPA's authority to regulate CO2 under the Clean Air Act. The Company expects the EPA to promulgate a new rule to regulate GHG emissions from power plants after a decision from the U.S. Supreme Court.

Water

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines ("ELG") for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule. While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation. The EPA anticipates releasing a proposed rule in fall 2022. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants in Texas.

Byproducts, Wastes, Hazardous Materials and Contamination

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amended the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. In 2019 and 2020, the EPA proposed several changes to this rule. On August 28, 2020, the EPA finalized "A Holistic Approach to Close Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing impoundments with an alternative liner.

33

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis below has been organized as follows:

•Executive summary, including introduction and overview, business strategy, and changes to the business environment

during the period, including environmental and regulatory matters;

•Results of operations;

•Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements,     

commitments, and off-balance sheet arrangements; and

•Known trends that may affect NRG's results of operations and financial condition in the future.

As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three months ended March 31, 2022 and 2021. Also refer to NRG's 2021 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: General section; Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Estimates section.

Executive Summary

Introduction and Overview

NRG is a consumer services company built on dynamic retail brands. NRG brings the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. The Company sells power, natural gas, home and power services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy. The Company has a customer base that includes approximately 6 million Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of generation as of March 31, 2022.

Strategy

NRG's strategy is to maximize stockholder value through the safe production and sale of reliable electricity and natural gas to its customers in the markets it serves, while positioning the Company to provide innovative solutions to the end-use energy or service consumer. This strategy is intended to enable the Company to optimize the integrated model to generate stable and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is a philosophy that underpins and facilitates value creation across our business for our stakeholders. It is an integral piece of NRG's strategy and ties directly to business success, reduced risks and enhanced reputation.

To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial and industrial, and wholesale customers in competitive markets through multiple brands and channels; (ii) offering a variety of energy products and services, including renewable energy solutions, that are differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) excellence in operating performance of its assets; (iv) optimal hedging of its portfolio; and (v) engaging in disciplined and transparent capital allocation.

The Company implemented a four-year plan that began in 2022 to spend $2 billion in order to achieve growth through optimization of the Company’s core power and natural gas sales, as well as integrated solution sales within our core network in both power and home services.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2021 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 16, Regulatory Matters.

As participants in wholesale and retail energy markets and owners and operators of power plants, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC and the PUCT, as well as other public utility commissions in certain states where NRG's generation or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states and provinces in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.

34

NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to NRG's ownership interest in STP.

Federal Energy Regulation

Congress continues to consider using the budget reconciliation process to pass energy efficiency and clean energy tax incentives included in President Biden's original Build Back Better initiative. NRG is monitoring these priorities as they progress through the legislative process.

State and Provincial Energy Regulation

Illinois Legislation — Illinois enacted the Climate and Equitable Jobs Act ("CEJA") on September 15, 2021, which targets 100% clean energy by 2050. CEJA focuses on (i) decarbonization, (ii) incentives to transition coal plants into clean energy facilities and (iii) nuclear subsidies. CEJA requires non-publicly owned coal or oil electric generating units larger than 25 MWs to eliminate CO2e and copollutant emissions by January 1, 2030. Non-publicly owned electric generating units that are gas-fired, including Joliet, must eliminate CO2e and copollutant emissions, including through unit retirement or the use of 100% green hydrogen, in a timeframe ranging from January 1, 2030 to January 1, 2045 depending on certain emission rates and proximity to environmental justice communities. Furthermore, CEJA placed restrictions, with immediate effect, on gas-fired units that limits future emissions to their historic baselines. These limits affect the total potential energy production by gas units in Illinois. PJM and the Illinois Environmental Protection Agency have issued guidance in an attempt to clarify the implications of these restrictions. The new energy law also provides $174 million in incentives to develop solar and battery storage at coal generating sites that may be available to NRG.

Regional Regulatory Developments

NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 16, Regulatory Matters.

Texas

Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — In September 2021, the PUCT opened a rulemaking project to evaluate whether it should amend its rules to modify the High System Wide Offer cap ("HCAP") and the ORDC, which is intended to ensure prices in the competitive market appropriately reflect the value of operating reserves as the system approaches scarcity conditions. This rulemaking project concluded in December 2021, resulting in a rule amendment that lowered the HCAP to $5,000 per MWh and which expanded the minimum contingency level to 3,000 MW in Phase I. These two changes are broadly offsetting in their effect on overall average energy prices. In 2022, the PUCT has focused on the development of a winter firm fuel product. While dual fuel capability with on-site fuel storage is the near-term target, the PUCT is still considering the specific eligibility requirements, program size and contract terms. For Phase II, the PUCT Chair endorsed a version of NRG's Load-Serving Entity Reliability Obligation ("LSERO") idea; that retailers and other LSEs should be obliged to purchase an amount of physical reliability resources at critical hours commensurate with the state's newly cautious view of planning for tail events. The PUCT has prioritized the development of a Backstop Reserve Service prior to consideration of an LSERO. ERCOT resource constraints will delay implementation, including Phase II items, by 12 to 24 months. Recently, the South Texas Electric Cooperative ("STEC") has filed a proposal to create a net-load based capacity market that allocates costs to loads, renewables and thermal resources with forced outages. A broad group of stakeholders, including NRG, have expressed support for the PUCT to include the STEC proposal in the blueprint for further review alongside the LSERO even though there is opposition for the specific cost allocation mechanism.

Activity on Securitization and ERCOT Pricing during Winter Storm Uri — The Texas Legislature acted to pass a variety of securitization vehicles to finance exceptionally high power and gas costs from Winter Storm Uri, including HB 4492. ERCOT subsequently filed two applications requesting the PUCT to issue Debt Obligation Orders ("DOOs") based on the legislation. On October 13, 2021, the PUCT issued DOOs authorizing ERCOT's securitization of $800 million to cover short payments and reimburse congestion revenue right account holders for amount related to the default of market participants other than electric cooperatives Brazos Electric Cooperative Inc. ("Brazos") and Rayburn Country Electric Cooperative, Inc. ("Rayburn"), which are discussed below (the "Default Securitization") and $2.1 billion related to highly priced ancillary service and ORPDA during Winter Storm Uri (the "Uplift Securitization").

The DOOs require ERCOT to issue loans or securitized bonds through a bankruptcy remote special purpose entity as the borrower and distribute the proceeds to affected market participants for default-related short payments and to LSEs for certain ancillary-service and ORDPA costs using an allocation of proceeds based on an LSE's exposure to relevant costs as calculated by the LSE's prevailing load-ratio share during the period of Winter Storm Uri, and a further redistribution of proceeds initially allocated to other LSEs and customers who opt-out of securitization. In turn, ERCOT will charge non-bypassable fees related to the Default Securitization and Uplift Securitization to all qualified scheduling entities and to all LSEs (other than those that have opted-out), respectively. The Uplift Securitization provided for a one-time opt-out for certain LSEs or individual

35

transmission-level customers who in exchange for foregoing any securitization-related proceeds likewise avoid future fees assessed by ERCOT for the use of repaying ERCOT's debt obligations. However, nearly all competitive REPs were required by the law to participate, ensuring the charge established by the law is competitively neutral. These opt-outs and calculations of the allocation of proceeds have been finalized. Based on LSE-level detail published by the PUCT on December 7, 2021, NRG will receive $689 million of Uplift Securitization proceeds, with receipt expected to occur during the second quarter of 2022. The $800 million Default Securitization was disbursed by ERCOT in November 2021, with NRG receiving $12 million.

Electric Cooperative Bankruptcy and Securitization — Of the defaults in the ERCOT market, the majority is attributable to Brazos. Brazos currently is in bankruptcy. NRG and ERCOT have both filed a proof of claim in the bankruptcy proceeding of Brazos, and Brazos has challenged ERCOT's claim in a manner that may prejudice NRG's claims against Brazos. During the fourth quarter of 2021, ERCOT filed a motion to dismiss Brazos' complaint relating to ERCOT's proof of claim, which NRG joined in support, but this motion was denied by the Bankruptcy Court, and ERCOT, NRG and certain other parties appealed. On January 11, 2022, the United States District Court for the Southern District of Texas entered an order allowing the appellants to seek direct review from the Fifth Circuit Court of Appeals of the Bankruptcy Court's decision on the motion to dismiss. On January 18, 2022, ERCOT, NRG and certain other parties filed a petition for direct review by the United States Court of Appeals for the Fifth Circuit. The Court of Appeals granted the petition on February 4, 2022. On February 7, 2022, the Bankruptcy Court entered an order granting summary judgment in favor of Brazos on whether ERCOT's sales to Brazos were in the ordinary course of Brazos' business. The Bankruptcy Court ruled that the portion of ERCOT's claims for charges incurred by Brazos after the intervention of the PUCT and ERCOT were not in the ordinary course and thus are not entitled to administrative expense status under the Bankruptcy Code. The amount and priority of ERCOT's claim for amounts incurred prior to such intervention or after such intervention ceased are issues to be determined at trial. The Bankruptcy Court's summary judgment ruling may also apply to NRG's claims again Brazos. To the extent the Bankruptcy Court reduces or disallows claims against Brazos, this presents risk for NRG.

Trial on the merits of the ERCOT proof of claim and Brazos' complaint commenced on February 22, 2022. On the eighth day of trial, the parties agreed to suspend the trial and pursue mediation. On March 25, 2022, the Bankruptcy Court entered an order that appointed a mediator and abated the trial for the duration of the mediation. On April 7, 2022, the Fifth Circuit Court of Appeals entered an order extending briefing deadlines applicable to the pending appeal of the Bankruptcy Court's ruling on the motion to dismiss. NRG is participating in the mediation with ERCOT, Brazos and various other parties in interest. The mediation is currently schedule to terminate on April 25, 2022, but it may be extended by agreement of the parties or an order of the Bankruptcy Court.

ERCOT's market protocols provide for short payments to be extinguished through a process of uplift, whereby the cost of defaults is allocated to all market participants, including retailers, generators, municipal and cooperative utilities, and financial traders. However, the total amount of this uplift is limited by ERCOT's current protocols of $2.5 million per month. Consequently, it would take approximately 63 years for the net short-pay balance of $1.887 billion related to Brazos to be uplifted to the market under the current market rules. NRG's undiscounted share of the uplift based on its current market share is estimated to be approximately $121 million and has been short-paid $68 million. The remaining $53 million has been discounted based on the 63 year repayment term and present value of $9 million was recorded as an additional liability.

In February 2022, Rayburn successfully completed a securitization transaction, and fully paid its outstanding obligations to ERCOT.

PJM

Indian River RMR Proceeding — On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4, effective May 31, 2022, due to expected uneconomic operations. On July 30, 2021, PJM responded to the deactivation notice and stated that PJM had identified reliability violations resulting from the proposed deactivation of Unit 4. NRG filed a cost based RMR rate schedule at FERC on April 1, 2022, seeking a June 1, 2022 effective date.

PJM Revisions to Minimum Offer Price Rule — On July 30, 2021, PJM filed a proposed tariff change at FERC to largely eliminate the current minimum offer price rules ("MOPR") except in very narrow cases. The proposal would eliminate: (i) the current MOPR for new entrant natural gas resources effective with the 2023/2024 delivery year and (ii) the expanded MOPR established in FERC's December 2019 Order to address out-of-market subsidies. On September 30, 2021, PJM's proposal went into effect by operation of law because the FERC Commissioners were split 2-2 as to the lawfulness of the change. Multiple parties filed motions for rehearing and ultimately appealed to the federal court of appeals. On December 21, 2021 and December 30, 2021, respectively, the Third Circuit Court of Appeals and the Seventh Circuit Court of Appeals issued an order holding the appeals in abeyance. The proposed revisions would allow PJM to address specific and narrow instances of buyer-side market power through subsequent filings at FERC. Any changes to the PJM capacity market construct may impact the outcome of future Base Residual Auctions.

PJM's ORDC Filing and Compliance Directives — On May 21, 2020, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which includes modifying its ORDC and aligning market-based reserve products

36

in Day-Ahead and Real-Time markets. In addition to approving PJM's proposal, FERC also directed PJM to implement a forward-looking Energy and Ancillary Services Offset to be used in PJM's capacity markets. After multiple compliance filings, parties filed appeals at the Court of Appeals for the D.C. Circuit of FERC’s orders, and on August 13, 2021, FERC filed a motion and was granted a voluntary remand the case back to the agency. On December 22, 2021, FERC issued its order on voluntary remand affirming in part and reversing in part FERC's determination. Specifically, FERC reversed itself and ordered PJM to: (i) eliminate the more robust ORDC curves and reserve penalty adders and maintain the existing (lower) curves and (lower) penalty adders and (ii) restore its tariff provisions related to its prior backward-looking Energy and Ancillary Services Offset. In response to requests for rehearing of the December 2021 order, FERC issued a notice denying the rehearings by operation of law and providing for further consideration. On February 22, 2022, multiple parties filed appeals of FERC's December 22, 2021 decision.

Independent Market Monitor Market Seller Offer Cap Complaint — On March 18, 2021, finding that the calculation of the default Market Seller Offer Cap was unjust and unreasonable, the Order permitted the current PJM May 2021 capacity auction for the 2022/2023 delivery rule to continue under the existing rules and set a procedural schedule for parties to file briefs with possible solutions. On September 2, 2021, FERC issued an order in response to a complaint filed by the PJM Independent Market Monitor's proposal, which eliminates the Cost of New Entry-based Market Seller Offer Cap and implements a limited default cap for certain asset classes based on going-forward costs and provides for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions. As required by the Order, PJM submitted its compliance tariff on October 4, 2021. On October 4, 2021, certain parties filed a motion for rehearing, which was denied by operation of law. On February 18, 2022, FERC addressed the arguments raised on rehearing and rejected the rehearing requests. Multiple parties filed appeals at the Court of Appeals for the D.C. Circuit. The appeals were held in abeyance, but on April 13, 2022, the Court of Appeals removed the appeals from abeyance and has ordered parties to provide a proposed briefing schedule. The revised rules will be effective for the next 2023/2024 Delivery Year Base Residual Auction, now delayed to June 2022.

New York

NYISO's Revisions to the Buyer-Side Mitigation Rules — On January 5, 2022, the NYISO filed its Comprehensive Mitigation Review proposing changes to the buyer-side mitigation rules. The proposal would remove certain facilities to be reviewed under the buyer-side mitigation rules to serve the goals of New York's Climate Leadership and Community Protection Act, adopt a marginal capacity accreditation market design and adjust the rules surrounding installed and unforced capacity. On February 9, 2022, FERC issued a deficiency notice, focusing on capacity accreditation issues. NYISO has responded to the deficiency notice and is awaiting Commission action. Changes to NYISO's Buyer Side Mitigation rules may impact the outcome of future capacity auctions.

California

California Resource Adequacy Proceedings — As part of the Integrated Resource Procurement docket, the CPUC approved a decision on June 24, 2021 that will require all Load Serving Entities to procure a pro rata share of 11.5 GW of new non-fossil resource adequacy from 2023 to 2026. A new resource adequacy docket opened in October 2021 is considering changes to the reserve margin and qualifying capacity of different resource types. Initial analysis performed by the CPUC is recommending an increase in the reserve margin from 15 to 20 percent beginning in 2024, and a decrease in the percent of nameplate capacity that intermittent resources can count toward resource adequacy compliance starting in 2023. The CPUC and CAISO are also continuing to evaluate major structural reforms to the resource adequacy program in California that would begin in 2024. On December 2, 2021, the CPUC directed the state's major investor-owned utilities to procure additional summer reliability resources on top of what had already been ordered in early 2021, up to 3 GW in total for the summers of 2021 through 2023. In the same docket, the CPUC expanded demand response programs for use during emergency conditions. The outcome of these proceedings could increase the cost to serve retail load in California.

Midway-Sunset Reliability Must Run Proceeding — San Joaquin Energy, LLC, a subsidiary of NRG, owns a 50%, non-controlling interest in the Midway-Sunset Cogeneration Company ("MSCC"). MSCC owns a cogeneration facility near Fellows, California and submitted mothball notices for the cogeneration facility to the CAISO in the latter half of 2020. On December 17, 2020, the CAISO Board effectively rejected the mothball notices by authorizing its staff to designate the MSCC facility as a RMR resource conditioned on execution of a RMR contract. On January 29, 2021, MSCC made its RMR filing at FERC. Multiple parties filed protests and on March 16, 2021, MSCC filed a response to those protests. On April 2, 2021, FERC accepted the RMR filing, suspended it to become effective February 1, 2021 subject to refund and established hearing and settlement judge proceedings. On September 27, 2021, the CAISO gave notice to MSCC extending the term of the reliability designation through December 31, 2022. On April 29, 2022, the participants in the settlement proceeding filed a Joint Offer of Settlement with the FERC. Comments on the Joint Offer of Settlement are due by May 19, 2022, with reply comments due by May 31, 2022.

37

Environmental Regulatory Matters

NRG is subject to numerous environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. Federal and state environmental laws historically have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the Company's operations. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.

A number of regulations that affect the Company have been revised recently by the EPA, including ash storage and disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. Some of these recent revisions may, in turn, be revised by the current U.S. presidential administration. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated revisions and legal challenges are resolved. The Company’s environmental matters are described in the Company’s 2021 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 17, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.

Air 

The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO2, ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS may become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below.

CPP/ACE Rules — The attention in recent years on GHG emissions has resulted in federal and state regulations. In October 2015, the EPA promulgated the CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. In July 2019, EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). On October 29, 2021, the U.S. Supreme Court agreed to review the D.C. Circuit's decision, which should provide some clarity regarding the scope of the EPA's authority to regulate CO2 under the Clean Air Act. The Company expects the EPA to promulgate a new rule to regulate GHG emissions from power plants after a decision from the U.S. Supreme Court.

Byproducts, Wastes, Hazardous Materials and Contamination

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amended the 2015 ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. In 2019 and 2020, the EPA proposed several changes to this rule. On August 28, 2020, the EPA finalized "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B: Alternative Demonstration for Unlined Surface Impoundments," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing ash impoundments with an alternate liner.

Domestic Site Remediation Matters

Under certain federal, state and local environmental laws, a current or previous owner or operator of a facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products. NRG may be responsible for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills during its operations. Further discussions of affected NRG sites can be found in Note 15, Commitments and Contingencies, to the condensed consolidated financial statements.

38

Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, had been required to enter into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.

On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Nuclear Waste Policy Act through December 31, 2013, which has been extended three times through addendums to cover payments through December 31, 2022. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.

Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended in 1985, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. Texas is currently in a compact with the state of Vermont, and the compact low-level waste facility located in Andrews County in Texas has been operational since 2012.

Water 

The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.

Effluent Limitations Guidelines — In November 2015, the EPA revised the ELG for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule. While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation. The EPA anticipates releasing a proposed rule in fall 2022. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants in Texas.

Regional Environmental Developments

Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that requires the state to promulgate regulations regarding coal ash at surface impoundments. On April 15, 2021, the state promulgated the implementing regulation, which became effective on April 21, 2021. The new regulation requires NRG to apply for initial operating permits for its coal ash surface impoundments by October 31, 2021 and construction permits (for closure) starting in 2022.

Significant Events

The following significant events have occurred during 2022 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:

Share Repurchases

In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock, of which $44 million was completed in 2021. During the first quarter of 2022, the Company completed $193 million of share repurchases at an average price of $38.78 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. Through April 30, 2022, an additional $76 million of share repurchases were executed at an average price of $38.00 per share.

Dividend Increase

In the first quarter of 2022, NRG increased the annual dividend to $1.40 from $1.30 per share, representing an 8% increase from 2021. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

39

Renewable Power Purchase Agreements

The Company's strategy is to procure mid to long-term generation through power purchase agreements. As of March 31, 2022, NRG has entered into PPAs totaling approximately 2.6 GW with third-party project developers and other counterparties, of which approximately 45% are operational. The average tenor of these agreements is twelve years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. The total GW entered into through PPAs may be impacted by contract terminations when they occur.

Limestone Unit 1 Return to Service

In early July 2021, Limestone Unit 1 came offline as a result of damage to the duct work associated with the flue gas desulfurization system. The extended forced outage ended in April of 2022 and the unit has returned to service.

COVID-19

While the pandemic presents risks to the Company's business, as further described in the Company’s 2021 Form 10-K in Part II, Item 1A — Risk Factors, there was not a material adverse impact on the Company’s results of operations for the three months ended March 31, 2022 and 2021.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2021 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.

40

Consolidated Results of Operations

The following table provides selected financial information for the Company:

	Three months ended March 31,
(In millions, except as otherwise noted)	2022		2021		Change
Revenue
Retail revenue	$	7,570	$	6,162	$	1,408
Energy revenue(a)	278		482		(204)
Capacity revenue(a)	116		155		(39)
Mark-to-market for economic hedging activities	(133)		(32)		(101)
Contract amortization	(9)		—		(9)
Other revenues(a)(b)	74		1,324		(1,250)
Total revenue	7,896		8,091		(195)
Operating Costs and Expenses
Cost of fuel	329		767		438
Purchased energy and other cost of sales(c)	6,452		6,416		(36)
Mark-to-market for economic hedging activities	(2,410)		(753)		1,657
Contract and emissions credit amortization(c)	138		1		(137)
Operations and maintenance	336		345		9
Other cost of operations	85		81		(4)
Cost of operations (excluding depreciation and amortization shown below)	4,930		6,857		1,927
Depreciation and amortization	183		317		134
Selling, general and administrative costs	322		337		15
Provision for credit losses	25		611		586
Acquisition-related transaction and integration costs	8		42		34
Total operating costs and expenses	5,468		8,164		2,696
(Loss)/gain on sale of assets	(3)		17		(20)
Operating Income/(Loss)	2,425		(56)		2,481
Other Income/(Expense)
Equity in (losses) of unconsolidated affiliates	(15)		(6)		(9)
Other income, net	—		22		(22)
Interest expense	(103)		(127)		24
Total other expense	(118)		(111)		(7)
Income/(Loss) Before Income Taxes	2,307		(167)		2,474
Income tax expense/(benefit)	571		(85)		(656)
Net Income/(Loss)	$	1,736	$	(82)	$	1,818
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	4.95	$	2.69	84		%

(a) Includes gains and losses from financially settled transactions

(b) Includes trading gains and losses and ancillary revenues

(c) Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits     

41

Management’s discussion of the results of operations for the three months ended March 31, 2022 and 2021

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended March 31, 2022 and 2021. The average on-peak power prices decreased significantly in Texas due to Winter Storm Uri's impact on 2021 pricing. East and West average on-peak power prices increased for the three months ended March 31, 2022 as compared to the same period in 2021 as a result of higher natural gas prices.

	Average on Peak Power Price ($/MWh)
	Three months ended March 31,
Region	2022		2021		Change %
Texas
ERCOT - Houston(a)	$	48.69	$	619.94	(92)	%
ERCOT - North(a)	46.27		621.04		(93)	%
East
NY J/NYC(b)	$	104.26	$	47.71	119	%
NEPOOL(b)	116.48		55.26		111	%
COMED (PJM)(b)	44.69		33.51		33	%
PJM West Hub(b)	58.33		35.09		66	%
West
MISO - Louisiana Hub(b)	$	43.49	$	40.70	7	%
CAISO - SP15(b)	45.20		44.74		1	%

(a)Average on peak power prices based on real time settlement prices as published by the respective ISOs

(b)Average on peak power prices based on day ahead settlement prices as published by the respective ISOs

The following table summarizes average realized power prices for NRG, including the impact of settled hedges, for the three months ended March 31, 2022 and 2021:

	Average Realized Power Price ($/MWh)
	Three months ended March 31,
Segment	2022		2021		Change %
East(a)	$	47.15	$	41.29	14	%
West/Services/Other	36.05		34.50		4	%

(a)Average Realized Power Price reflects energy sales from the generation fleet, including sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail business make up ($5.41)/MWh in the three months ended March 31, 2022 and $2.47/MWh in the three months ended March 31, 2021    

The average realized power prices increased in the East and West/Services/Other segments for the three months ended March 31, 2022 as compared to the same period in 2021, as a result of the Company's multi-year hedging program and higher natural gas prices.

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization and depreciation and amortization.

Economic Gross Margin

In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging

42

activities, contract amortization, emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended March 31, 2022 and 2021:

	Three months ended March 31, 2022
($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	$	1,952	$	4,521	$	1,097	$	—	$	7,570
Energy revenue	15		204		54		5		278
Capacity revenue	—		115		1		—		116
Mark-to-market for economic hedging activities	(2)		(130)		(18)		17		(133)
Contract amortization	—		(9)		—		—		(9)
Other revenue(a)	58		17		4		(5)		74
Total revenue	2,023		4,718		1,138		17		7,896
Cost of fuel	(175)		(103)		(51)		—		(329)
Purchased energy and other cost of sales(b)(c)(d)	(1,283)		(4,164)		(1,004)		(1)		(6,452)
Mark-to-market for economic hedging activities	655		1,576		196		(17)		2,410
Contract and emission credit amortization	2		(138)		(2)		—		(138)
Depreciation and amortization	(76)		(78)		(21)		(8)		(183)
Gross margin	$	1,146	$	1,811	$	256	$	(9)	$	3,204
Less: Mark-to-market for economic hedging activities, net	653		1,446		178		—		2,277
Less: Contract and emission credit amortization, net	2		(147)		(2)		—		(147)
Less: Depreciation and amortization	(76)		(78)		(21)		(8)		(183)
Economic gross margin	$	567	$	590	$	101	$	(1)	$	1,257
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $672 million, $61 million and $389 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail sales
Home power sales volume (GWh)	9,239		3,438		609		—		13,286
Business power sales volume (GWh)	8,691		12,148		2,117		—		22,956
Home natural gas sales volume (MDth)	—		40,158		39,285		—		79,443
Business natural gas sales volume (MDth)	—		529,897		41,965		—		571,862
Average retail Home customer count (in thousands) (a)(b)	3,011		1,773		792		—		5,576
Ending retail Home customer count (in thousands) (a)(b)	2,986		1,773		788		—		5,547
Power generation
GWh sold	8,021		3,881		1,498		—		13,400
GWh generated(c)
Coal	4,465		2,466		—		—		6,931
Gas	1,008		114		1,500		—		2,622
Nuclear	2,548		—		—		—		2,548
Renewables	—		—		1		—		1
Total	8,021		2,580		1,501		—		12,102
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) The whole home warranty business was sold in January 2022
(c) Includes owned and leased generation, excludes tolled generation and equity investments

43

	Three months ended March 31, 2021
($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	$	2,114	$	3,213	$	835	$	—	$	6,162
Energy revenue	285		126		70		1		482
Capacity revenue	—		141		14		—		155
Mark-to-market for economic hedging activities	(1)		(4)		(28)		1		(32)
Other revenue(a)	1,304		19		4		(3)		1,324
Total revenue	3,702		3,495		895		(1)		8,091
Cost of fuel	(724)		(18)		(25)		—		(767)
Purchased energy and other cost of sales(b)(c)(d)	(2,882)		(2,799)		(735)		—		(6,416)
Mark-to-market for economic hedging activities	525		166		63		(1)		753
Contract and emission credit amortization	(1)		—		—		—		(1)
Depreciation and amortization	(77)		(206)		(27)		(7)		(317)
Gross margin	$	543	$	638	$	171	$	(9)	$	1,343
Less: Mark-to-market for economic hedging activities, net	524		162		35		—		721
Less: Contract and emission credit amortization, net	(1)		—		—		—		(1)
Less: Depreciation and amortization	(77)		(206)		(27)		(7)		(317)
Economic gross margin	$	97	$	682	$	163	$	(2)	$	940
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $590 million, $53 million and $270 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail sales
Home power sales volume (GWh)	10,186		3,755		641		—		14,582
Business power sales volume (GWh)	6,524		12,926		2,360		—		21,810
Home natural gas sales volume (MDth)	—		36,597		41,533		—		78,130
Business natural gas sales volume (MDth)	—		479,634		33,617		—		513,251
Average retail Home customer count (in thousands)(a)(b)	2,987		1,909		975		—		5,871
Ending retail Home customer count (in thousands)(a)(b)	2,991		1,885		976		—		5,852
Power generation
GWh sold	7,349		3,245		2,029		—		12,623
GWh generated(c)
Coal	3,840		1,301		—		—		5,141
Gas(d)	1,185		107		1,985		—		3,277
Nuclear	2,324		—		—		—		2,324
Oil(e)	—		17		—		—		17
Total	7,349		1,425		1,985		—		10,759
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes 160 thousand whole home warranty customers in West/Services/Other. The whole home warranty business was sold in the first quarter of 2022
(c) Includes owned and leased generation, excludes tolled generation and equity investments
(d) Includes 126 GWh and 614 GWh in East and West/Services/Other, respectively, that was sold to Generation Bridge in December 2021
(e) Includes 17 GWh in East that was sold to Generation Bridge in December 2021

44

The table below represents the weather metrics for the three months ended March 31, 2022 and 2021:

	Three months ended March 31,
Weather Metrics	Texas	East	West/Services/Other (b)
2022
CDDs (a)	68	42	31
HDDs (a)	1,177	2,404	1,151
2021
CDDs	86	38	37
HDDs	1,120	2,350	1,201
10-year average
CDDs	112	39	50
HDDs	935	2,376	1,062

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period

(b) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central regions

Gross Margin and Economic Gross Margin

Gross margin increased $1.9 billion and economic gross margin increased $317 million during the three months ended March 31, 2022, compared to the same period in 2021.

The tables below describe the changes in gross margin and economic gross margin by segment:

Texas

	(In millions)
Higher gross margin due to the impact of Winter Storm Uri in 2021, primarily due to unhedgeable ancillary and operating reserve demand curve(a)	$	528
The following explanations exclude the impact of Winter Storm Uri:
Higher gross margin from increased load of 1.2 million MWhs due to weather	45
Lower gross margin due to a 35% increase in overall average costs to serve the retail load, driven primarily by the effect of the Limestone Unit 1 extended forced outage that began in the third quarter of 2021, the more conservative winter hedge profile in the first quarter of 2022, and increases in power, ancillary, and fuel costs, totaling $158 million, partially offset by increased net revenue rates of $4.00 per MWh, or $50 million, and higher gross margin attributable to increased load of 650,000 MWh, or $14 million, both offsets primarily driven by changes in customer mix	(94)
Lower gross margin from market optimization activities	(2)
Other	(7)
Increase in economic gross margin	$	470
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	129
Decrease in contract and emission credit amortization	3
Decrease in depreciation and amortization	1
Increase in gross margin	$	603

(a) For further discussion of ERCOT's securitization activity see Regional Regulatory Developments section under Energy Regulatory Matters above and Note 2, Summary of Significant Accounting Policies.

45

East

	(In millions)
Lower gross margin due to the impact of Winter Storm Uri in 2021, primarily due to natural gas optimization during volatile pricing	$	(154)
The following explanations exclude the impact of Winter Storm Uri:
Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021	(55)
Lower power gross margin from decreased load due to attrition and customer mix	(23)
Lower power gross margin from higher supply costs of $21.50 per MWh, primarily due to higher power prices, totaling $338 million, partially offset by higher net revenue rates as a result of changes in customer term, product and mix of $15.50 per MWh, or $247 million	(91)
Higher gross margin due to a 57% increase in average realized pricing and an increase in generation volumes due to dark spread expansion primarily at Midwest Generation; partially offset by an increase in supply costs	42
Higher natural gas gross margin including the impact of transportation and storage contract optimization, resulting in higher net revenue rates as a result of changes in customer term, product and mix of $2.75 per Dth, or $1.6 billion, partially offset by higher supply costs of $2.50 per Dth, primarily due to increases in natural gas costs, totaling $1.4 billion	160
Higher natural gas gross margin from increased load due to customer mix, partially offset by attrition	25
Other	4
Decrease in economic gross margin	$	(92)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	1,284
Increase in contract amortization	(147)
Decrease in depreciation and amortization	128
Increase in gross margin	$	1,173

West/Services/Other

	(In millions)
Lower gross margin due to the impact of Winter Storm Uri in 2021, primarily due to natural gas optimization during volatile pricing	$	(13)
The following explanations exclude the impact of Winter Storm Uri:
Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021	(20)
Lower gross margin due to the sale of the whole home warranty business in the first quarter of 2022	(8)
Higher power gross margin due to an increase in net revenue rates as a result of changes in customer term, product and mix of $25.25 per MWh, or $58 million, partially offset by higher supply costs of $22.50 per MWh, primarily due to increases in power prices, totaling $50 million	8
Lower natural gas gross margin due to higher supply costs of $1.27 per Dth, primarily due to increases in natural gas prices, totaling $103 million, partially offset by higher net revenue rates as a result of changes in customer term, product and mix of $0.65 per Dth, or $63 million, and increased load due to customer mix, totaling $18 million	(22)
Other	(7)
Decrease in economic gross margin	$	(62)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	143
Increase in contract amortization	(2)
Decrease in depreciation and amortization	6
Increase in gross margin	$	85

46

Mark-to-Market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results increased by $1.6 billion during the three months ended March 31, 2022, compared to the same period in 2021.

The breakdown of gains and losses included in revenues and operating costs and expenses by segment was as follows:

	Three months ended March 31, 2022
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	1	$	(22)	$	30	$	(2)	$	7
Reversal of acquired loss positions related to economic hedges	—		2		—		—		2
Net unrealized (losses) on open positions related to economic hedges	(3)		(110)		(48)		19		(142)
Total mark-to-market (losses) in revenue	$	(2)	$	(130)	$	(18)	$	17	$	(133)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(94)	$	(261)	$	(62)	$	2	$	(415)
Reversal of acquired loss/(gain) positions related to economic hedges	12		(68)		(6)		—		(62)
Net unrealized gains on open positions related to economic hedges	737		1,905		264		(19)		2,887
Total mark-to-market gains in operating costs and expenses	$	655	$	1,576	$	196	$	(17)	$	2,410

	Three months ended March 31, 2021
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	—	$	(15)	$	(4)	$	—	$	(19)
Reversal of acquired (gain) positions related to economic hedges	—		(3)		—		—		(3)
Net unrealized (losses)/gains on open positions related to economic hedges	(1)		14		(24)		1		(10)
Total mark-to-market (losses) in revenue	$	(1)	$	(4)	$	(28)	$	1	$	(32)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	33	$	3	$	—	$	—	$	36
Reversal of acquired loss positions related to economic hedges	36		112		—		—		148
Net unrealized gains on open positions related to economic hedges	456		51		63		(1)		569
Total mark-to-market gains in operating costs and expenses	$	525	$	166	$	63	$	(1)	$	753

`

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.

For the three months ended March 31, 2022, the $133 million loss in revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of increases in natural gas and power prices. The $2.4 billion gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases in natural gas and power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period and acquired contracts that settled during the period.

For the three months ended March 31, 2021, the $32 million loss in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period as well as a decrease in the value of open positions as a result of increases in West power prices. The $753 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases ERCOT power prices and ERCOT heat rate expansion, as well as the reversal of acquired deals and previously recognized unrealized losses on contracts that settled during the period.

47

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended March 31, 2022 and 2021. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.

	Three months ended March 31,
(In millions)	2022		2021
Trading gains/(losses)
Realized	$	7	$	59
Unrealized	(14)		4
Total trading (losses)/gains	$	(7)	$	63

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Three months ended March 31, 2022	$	189	$	101	$	47	$	—	$	(1)	$	336
Three months ended March 31, 2021	188		103		55		—		(1)		345

Operations and maintenance expense decreased by $9 million for the three months ended March 31, 2022, compared to the same period in 2021, due to the following:

	(In millions)
Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021	$	(24)
Decrease due to the duration and scope of planned and forced outages at Midwest Generation and in Texas during 2022 as compared to 2021	(5)
Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation in 2022 as compared to 2021	15
Other	5
Decrease in operations and maintenance expense	$	(9)

Other Cost of Operations

Other cost of operations are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Total
Three months ended March 31, 2022	$	42	$	37	$	6	$	85
Three months ended March 31, 2021	43		35		3		81

Other costs of operations increased by $4 million for the three months ended March 31, 2022, compared to the same period in 2021, due to the following:

	(In millions)
Increase in retail gross receipt taxes due to higher retail revenue	$	6
Increase due to changes in current year ARO cost estimates and the timing of ARO spend	4
Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021	(8)
Other	2
Increase in other cost of operations	$	4

48

Depreciation and Amortization

Depreciation and amortization are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Corporate		Total
Three months ended March 31, 2022	$	76	$	78	$	21	$	8	$	183
Three months ended March 31, 2021	77		206		27		7		317

Depreciation and amortization decreased by $134 million for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to adjustments to acquired intangibles in the second quarter of 2021 in connection with the acquisition of Direct Energy.

Selling, General and Administrative Costs

Selling, general and administrative costs are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Three months ended March 31, 2022	$	144	$	117	$	49	$	12	$	—	$	322
Three months ended March 31, 2021	145		141		41		11		(1)		337

Selling, general and administrative costs decreased by $15 million for the three months ended March 31, 2022, compared to the same period in 2021, due to the following:

	(In millions)
Decrease due to Winter Storm Uri in 2021	$	(21)
Decrease primarily due to lower information technology-related contracts and services expenses	(9)
Decrease in transition service agreement costs related to the Direct Energy acquisition	(6)
Increase in legal, consulting and software costs	9
Increase in broker fee expenses, partially offset by lower commissions expenses	4
Other	8
Decrease in selling, general and administrative costs	$	(15)

Provision for Credit Losses

Provision for credit losses are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Total
Three months ended March 31, 2022	$	3	$	14	$	8	$	25
Three months ended March 31, 2021	602		6		3		611

Provision for credit losses decreased by $586 million for the three months ended March 31, 2022, compared to the same period in 2021, due to the following:

	(In millions)
Decrease due to the impact of Winter Storm Uri in 2021, including:    Decrease of $393 million related to bilateral financial hedging risk    Decrease of $109 million related to counterparty credit risk    Decrease of $83 million related to ERCOT default shortfall payments	$	(585)
Other	(1)
Decrease in provision for credit losses	$	(586)

49

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $8 million were incurred during the three months ended March 31, 2022, which are comprised primarily of integration costs related to Direct Energy.

Acquisition-related transaction and integration costs of $42 million were incurred during the three months ended March 31, 2021, related to Direct Energy, of which $22 million were acquisition-related transaction costs and $20 million were integration costs primarily related to severance and consulting services.

(Loss)/Gain on Sale of Assets

The loss on sale of assets of $3 million for the three months ended March 31, 2022 was related to an adjustment to the proceeds on the sale of fossil generating assets to Generation Bridge in December of 2021. The gain on sale of assets of $17 million for the three months ended March 31, 2021 was related to the sale of Agua Caliente in February of 2021.

Interest Expense

Interest expense decreased by $24 million for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to debt reduction and refinancing of debt to lower interest rates in the second half of 2021.

Income Tax Expense/(Benefit)

For the three months ended March 31, 2022, income tax expense of $571 million was recorded on pre-tax income of $2.3 billion. For the same period in 2021, an income tax benefit of $85 million was recorded on a pre-tax loss of $167 million. The effective tax rates were 24.8% and 50.9% for the three months ended March 31, 2022 and 2021, respectively.

For the three months ended March 31, 2022, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense. For the same period in 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax benefits and one-time tax benefits, as a result of the acquisition of Direct Energy, on the revaluation of state deferred tax assets, NOLs, and valuation allowance.

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2022 and December 31, 2021, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $2.9 billion and $2.7 billion, respectively, was comprised of the following:

(In millions)	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	387	$	250
Restricted cash - operating	7		4
Restricted cash - reserves(a)	32		11
Total	426		265
Total availability under Revolving Credit Facility and collective collateral facilities(b)	2,491		2,421
Total liquidity, excluding funds deposited by counterparties	$	2,917	$	2,686

(a) Includes reserves primarily for performance obligations

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $6 billion and $5.9 billion as of March 31, 2022 and December 31, 2021, respectively

For the three months ended March 31, 2022, total liquidity, excluding funds deposited by counterparties, increased by $231 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at March 31, 2022 were predominantly held in bank deposits.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

The Company remains committed to maintaining a strong balance sheet and continues to work to achieve investment grade credit metrics. The Company expects to grow into its target investment grade metrics primarily through the realization of Direct Energy run-rate earnings and other growth initiatives.

50

Liquidity

The principal sources of liquidity for NRG's future operating and maintenance capital expenditures are expected to be derived from cash on hand, cash flows from operations, and financing arrangements. As described in Note 8, Long-term Debt and Finance Leases, to this Form 10-Q, the Company's financing arrangements consist mainly of the Senior Notes, Convertible Senior Notes, Senior Secured First Lien Notes, Revolving Credit Facility, and tax-exempt bonds.

The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) market operations activities; (ii) debt service obligations; as described more fully in Note 8, Long-term Debt and Finance Leases (iii) capital expenditures, including maintenance, repowering, development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Note 10, Changes in Capital Structure.

ERCOT Securitization Proceeds

During 2021, the Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri. The Company expects to receive proceeds of $689 million from ERCOT in the second quarter of 2022.

Repurchase Facility

On February 9, 2022, the Company entered into amendments to its existing Repurchase Facility to, among other things, (i) increase the size of the facility from $75 million to $150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate. The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%. As of March 31, 2022, there were no outstanding borrowings.

Bilateral Letter of Credit Facilities

On April 29, 2022, the Company increased the size of the facilities by $100 million to provide additional liquidity, allowing for the issuance of up to $575 million of letters of credit.

CARES Act

On March 27, 2020, the U.S. government enacted the CARES Act, which provides, among other things: (i) the option to defer payments of certain 2019 employer payroll taxes incurred after the date of enactment; and (ii) allows NOLs from tax years 2018, 2019 and 2020 to be carried back five years. The total benefit to the Company due to the CARES Act was $35 million. Of this amount, $13 million related to certain 2019 employer payroll taxes is payable in 2022.

Market Operations

The Company's market operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (e.g., buying energy before receiving retail revenues); and (iv) initial collateral for large structured transactions. As of March 31, 2022, the Company had total cash collateral outstanding of $9 million and $3.5 billion outstanding in letters of credit to third parties primarily to support its market activities. As of March 31, 2022, total funds deposited by counterparties were $2.6 billion in cash and $593 million of letters of credit.

Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements depend on the Company's credit ratings and general perception of its creditworthiness.

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, subject to various exclusions including NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The first lien program does not limit the volume that can be hedged, or the value of underlying out-of-the-money positions. The first lien program also does not require NRG to post collateral above any threshold amount of exposure. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of March 31, 2022, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.

51

The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of March 31, 2022:

Equivalent Net Sales Secured by First Lien Structure(a)	2022	2023
In MW	656	735
As a percentage of total net coal and nuclear capacity(b)	15%	17%

(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region

(b) Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien, which excludes coal assets acquired with Midwest Generation and NRG's assets that have project level financing

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental and growth investments for the three months ended March 31, 2022, and the estimated capital expenditures forecast for the remainder of 2022.

(In millions)	Maintenance		Environmental		Growth Investments(a)		Total
Texas	$	(35)	$	(1)	$	(3)	$	(39)
East	(1)		—		(3)		(4)
West/Services/Other	(6)		—		—		(6)
Corporate	(1)		—		(10)		(11)
Total cash capital expenditures for the three months ended March 31, 2022	(43)		(1)		(16)		(60)
Investments	—		—		(31)		(31)
Total capital expenditures and investments	(43)		(1)		(47)		(91)
Estimated capital expenditures and investments for the remainder of 2022	$	(202)	$	(7)	$	(168)	$	(377)

(a) Includes other investments, acquisitions and integration projects

Growth investments for the three months ended March 31, 2022 include expenditures for Encina site improvements classified as ARO payments. Demolition is underway and is expected to be completed in the first half of 2022. The Company expects to begin marketing the site in 2022.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2022 through 2026 required to comply with environmental laws will be approximately $56 million, primarily driven by the cost of complying with ELG at the Company's coal units in Texas.

Share Repurchases

In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock, of which $44 million was completed in 2021. During the first quarter of 2022, the Company completed $193 million of share repurchases at an average price of $38.78 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. Through April 30, 2022, an additional $76 million of share repurchases were executed at an average price of $38.00 per share.

Common Stock Dividends

During the first quarter of 2022, NRG increased the annual dividend to $1.40 from $1.30 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.35 per share was paid on the Company's common stock during the three months ended March 31, 2022. On April 20, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, payable on May 16, 2022 to stockholders of record as of May 2, 2022.

Obligations under Certain Guarantees

NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the Company’s business activities. For further discussion, see Note 27, Guarantees, to the Company's 2021 Form 10-K.

52

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of March 31, 2022, NRG has investments in energy and energy-related entities that are accounted for under the equity method of accounting. NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. See also Note 9, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $531 million as of March 31, 2022. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 17, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2021 Form 10-K.

Contractual Obligations and Market Commitments

NRG has a variety of contractual obligations and other market commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2021 Form 10-K. See also Note 8, Long-term Debt and Finance Leases, and Note 15, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and market commitments that occurred during the three months ended March 31, 2022.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative three month periods:

	Three months ended March 31,
(In millions)	2022		2021		Change
Net Cash Provided/(Used) by Operating Activities	$	1,676	$	(917)	$	2,593
Net Cash Used by Investing Activities	(80)		(3,364)		3,284
Net Cash Provided by Financing Activities	287		924		(637)

Net Cash Provided/(Used) by Operating Activities

Changes to net cash provided/(used) by operating activities were driven by:

	(In millions)
Changes in cash collateral in support of risk management activities due to change in commodity prices	$	2,006
Increase in working capital primarily due to the impact of Winter Storm Uri in 2021	596
Decrease in operating income adjusted for other non-cash items	(85)
Increase in working capital primarily due to higher usage of natural gas inventories	76
	$	2,593

Net Cash Used by Investing Activities

Changes to net cash provided/(used) by investing activities were driven by:

	(In millions)
Decrease in cash paid for acquisitions primarily due to the Direct Energy acquisition in 2021	$	3,456
Decrease in proceeds from sale of assets primarily due to the sale of Agua Caliente in 2021	(183)
Increase in proceeds from sales of investments in nuclear decommissioning trust fund securities, net of purchases	21
Increase in purchases of emissions allowances	(13)
Decrease in capital expenditures	3
	$	3,284

53

Net Cash Provided by Financing Activities

Changes to net cash (used)/provided by financing activities were driven by:

	(In millions)
Decrease in proceeds from Revolving Credit Facility and Receivables Securitization Facilities	$	(825)
Increase in net receipts from settlement of acquired derivatives	371
Increase in payments for share repurchase activity	(179)
Increase in payments of dividends to common stockholders	(5)
Other	1
	$	(637)

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740

For the three months ended March 31, 2022, the Company had domestic pre-tax book income of $2.3 billion and foreign pre-tax book loss of $8 million. As of December 31, 2021, the Company had cumulative U.S. Federal NOL carryforwards of $8.4 billion, of which $11 million were generated prior to Tax Cuts and Jobs Act and will begin expiring in 2031, and cumulative state NOL carryforwards of $5.2 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $383 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $20 million indefinite carryforward for interest deductions, as well as $384 million of tax credits to be utilized in future years. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates net income tax payments, due to federal, state and foreign jurisdictions, of up to $45 million in 2022.

As of March 31, 2022, the Company has $18 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability of $19 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority.

The Company is no longer subject to U.S. federal income tax examinations for years prior to 2017. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2013.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of March 31, 2022 and December 31, 2021, NRG recorded a net deferred tax asset, excluding valuation allowance, of $1.8 billion and $2.3 billion, respectively. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of March 31, 2022 as discussed below.

NOL Carryforwards — As of March 31, 2022, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.8 billion and $328 million, respectively. The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before the expiration of certain carryforwards commences in 2031. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $101 million with no expiration date.

Valuation Allowance — As of March 31, 2022 and December 31, 2021, the Company’s tax-effected valuation allowance was $233 million and $248 million, respectively, consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary differences.

Guarantor Financial Information

As of March 31, 2022, the Company's outstanding registered senior notes consisted of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes as shown in Note 8, Long-term Debt and Finance Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”). See Exhibit 22.1 for a listing of the Guarantors. These guarantees are both joint and several.

NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the Guarantors to transfer funds to NRG. Other subsidiaries of the Company do not guarantee the registered debt securities of either NRG Energy, Inc or the Guarantors (such subsidiaries are referred to as the “Non-Guarantors”). The Non-Guarantors include all of NRG's foreign subsidiaries and certain domestic subsidiaries.

54

The tables below present summarized financial information of NRG Energy, Inc. and the Guarantors in accordance with Rule 3-10 under the SEC's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP.

The following table presents the summarized statement of operations:

(In millions)	Three months ended March 31, 2022		Three months ended March 31, 2021
Revenues(a)	$	6,866	$	7,220
Operating income(b)	2,532		(46)
Total other expense	(95)		(100)
Income from continuing operations before income taxes	2,436		(146)
Net Income	1,864		(57)

(a)Intercompany transactions with Non-Guarantors of $81 million and $7 million during the three months ended March 31, 2022 and 2021, respectively

(b)Intercompany transactions with Non-Guarantors including cost of operations of $(64) million and $(53) million and selling, general and administrative of $34 million and $23 million during the three months ended March 31, 2022 and 2021, respectively

The following table presents the summarized balance sheet information:

(In millions)	March 31, 2022		December 31, 2021
Current assets(a)	$	15,480	$	9,399
Property, plant and equipment, net	1,311		1,324
Non-current assets	11,533		11,569
Current liabilities(b)	11,816		7,590
Non-current liabilities	11,765		11,195

(a)Includes intercompany receivables due from Non-Guarantors of $40 million and $86 million as of March 31, 2022 and December 31, 2021, respectively

(b)Includes intercompany payables due from Non-Guarantors of $36 million and $50 million as of March 31, 2022 and December 31, 2021, respectively

Fair Value of Derivative Instruments

NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at power plants or retail load obligations. In addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.

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.

55

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at March 31, 2022, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2022. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.

Derivative Activity Gains/(Losses)	(In millions)
Fair Value of Contracts as of December 31, 2021	$	2,341
Contracts realized or otherwise settled during the period	(475)
Changes in fair value	2,731
Fair Value of Contracts as of March 31, 2022	$	4,597

	Fair Value of Contracts as of March 31, 2022
(In millions)	Maturity
Fair Value Hierarchy Gains	1 Year or Less		Greater than 1 Year to 3 Years		Greater than 3 Years to 5 Years		Greater than 5 Years		Total Fair Value
Level 1	$	923	$	372	$	48	$	12	$	1,355
Level 2	1,765		703		154		92		2,714
Level 3	325		90		24		89		528
Total	$	3,013	$	1,165	$	226	$	193	$	4,597

The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or posted on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3, Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of March 31, 2022, NRG's net derivative asset was $4.6 billion, an increase to total fair value of $2.3 billion as compared to December 31, 2021. This increase was primarily driven by gains in fair value, partially offset by roll-off of trades that settled during the period.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $1.2 billion in the net value of derivatives as of March 31, 2022.

The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $1.3 billion in the net value of derivatives as of March 31, 2022.

Critical Accounting Estimates

NRG's discussion and analysis of the financial condition and results of operations are based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of appropriate technical accounting rules and guidance involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.

56

NRG evaluates these estimates, on an ongoing basis, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.

The Company identifies its most critical accounting estimates as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.

The Company's critical accounting estimates are described in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in the Company's 2021 Form 10-K. There have been no material changes to the Company's critical accounting estimates since the 2021 Form 10-K.

57

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's retail operations, merchant power generation or with existing or forecasted financial or commodity transactions. The types of market risks the Company is exposed to are commodity price risk, credit risk, liquidity risk, interest rate risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2021 Form 10-K.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's load serving obligations and merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of energy and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, gas transportation and storage assets, load obligations and bilateral physical and financial transactions, based on historical and forward values for factors such as customer demand, weather, commodity availability and commodity prices. The Company's VaR model is based on a one-day holding period at a 95% confidence interval for the forward 36 months, not including the spot month. The VaR model is not a complete picture of all risks that may affect the Company's results. Certain events such as counterparty defaults, regulatory changes, and extreme weather and prices that deviate significantly from historically observed values are not reflected in the model.

The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, calculated using the VaR model for the three months ending March 31, 2022 and 2021:

(In millions)	2022		2021
VaR as of March 31, (a)	$	40	$	30
Three months ended March 31,
Average(b)	$	37	$	31
Maximum(b)	57		36
Minimum(b)	27		25

(a)Calculation includes entire NRG portfolio as of March 31, 2021

(b)Calculation is based on NRG generation assets and load obligations excluding the acquisition of Direct Energy assets and load obligations in the first quarter of 2021

In order to provide additional information, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model for the entire term of these instruments entered into for both asset management and trading, was $368 million, as of March 31, 2022, primarily driven by asset-backed and hedging transactions.

Credit Risk

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. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities. Counterparty credit risk and retail customer credit risk are discussed below. See Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2021 Form 10-K. As of March 31, 2022, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $3.2 billion and NRG held collateral (cash and letters of credit) against those positions of $1.5 billion, resulting in a net exposure of $1.8 billion. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 82% of the Company's exposure before collateral is expected to roll off by the end of 2023. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and

58

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.

	Net Exposure(a)(b)
Category by Industry Sector	(% of Total)
Utilities, energy merchants, marketers and other	59	%
Financial institutions	41
Total as of March 31, 2022	100	%

	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	59	%
Non-investment grade/non-rated	41
Total as of March 31, 2022	100	%

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

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

The Company currently has no exposure to wholesale counterparties in excess of 10% of total net exposure discussed above as of March 31, 2022. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

During the first quarter of 2021, during Winter Storm Uri, the Company experienced a nonperformance by a counterparty in one of its bilateral financial hedging transactions, resulting in exposure of $393 million. The Company is pursuing all means available to enforce its obligations under this transaction but, given the size of the exposure and the counterparty filing for Chapter 11 bankruptcy protection, cannot determine with certainty what the amount of its ultimate recovery will be. The full exposure was recorded as a provision for credit losses as of March 31, 2021.

RTOs and ISOs

The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, whereas in the case of ERCOT, it is approved by the PUCT, and whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO to the Ontario Energy Board. These ISOs may include 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 the overall market and are excluded from the above exposures.

Exchange Traded Transactions

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

Long-Term Contracts

Counterparty credit exposure described above excludes credit risk exposure under certain long-term contracts, primarily solar PPAs. As external sources or observable market quotes are not always 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 March 31, 2022, aggregate credit risk exposure managed by NRG to these counterparties was approximately $1.2 billion for the next five years.

Retail Customer Credit Risk

The Company is exposed to retail credit risk through the Company's retail electricity and gas providers, which serve Home and Business customers. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both non-payment 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.

59

As of March 31, 2022, the Company's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. 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.

Liquidity Risk

Liquidity risk arises from the general funding needs of the Company's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline, primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.

Based on a sensitivity analysis for power and gas positions under marginable contracts as of March 31, 2022, a $0.50 per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin collateral posted of approximately $778 million and a 1.00 MMBtu/MWh decrease in heat rates for heat rate positions would result in an increase in margin collateral posted of approximately $331 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2022.

Interest Rate Risk

As of March 31, 2022, the fair value and related carrying value of the Company's debt was $7.8 billion and $8.1 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt as of March 31, 2022 by $614 million.

Currency Exchange Risk

NRG is subject to transactional exchange rate risk from transactions with customers in countries outside of the United States, primarily within Canada, as well as from intercompany transactions between affiliates. Transactional exchange rate risk arises from the purchase and sale of goods and services in currencies other than our functional currency or the functional currency of an applicable subsidiary. NRG hedges a portion of its forecasted currency transactions with foreign exchange forward contracts. As of March 31, 2022, NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business and entered into foreign exchange contracts with notional amount of $264 million.

The Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the United States are translated into U.S. dollars using exchange rates effective during the respective period. As a result, the Company is exposed to movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and Australian dollars. A hypothetical 10% appreciation in major currencies relative to the U.S. dollar as of March 31, 2022 would have resulted in an immaterial impact to net income within the Consolidated Statement of Operations.

60

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.

Changes in Internal Control over Financial Reporting

There were no changes in NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the quarter ended March 31, 2022 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

61

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through March 31, 2022, see Note 15, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

During the three months ended March 31, 2022, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company's 2021 Form 10-K.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended March 31, 2022.

For the three months ended March 31, 2022	Total Number of Shares Purchased	Average Price Paid per Share(b)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(a)(c)
Month #1
(January 1, 2022 to January 31, 2022	1,640,000	$	40.22	1,640,000	$	884,043,371
Month #2
(February 1, 2022 to February 28, 2022,	249,151	$	39.04	249,151	$	874,264,566
Month #3
(March 1, 2022 to March 31, 2022)	2,941,238	$	37.76	2,941,238	$	763,150,724
Total at March 31, 2022	4,830,389	$	38.66	4,830,389

(a)On December 6, 2021 the Company announced that the Board of Directors has authorized $1 billion for share repurchases, as part of NRG’s capital allocation program. The program began in December 2021 and continues in 2022

(b)The average price paid per share excludes commissions of $0.02 per share paid in connection with the open market share repurchases

(c)Includes commissions of $0.02 per share paid in connection with the open market share repurchases

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Form 10-Q.

ITEM 5 — OTHER INFORMATION

None.

62

ITEM 6 — EXHIBITS

Number	Description	Method of Filing
22.1	List of Guarantor Subsidiaries	Filed herewith.
31.1	Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.	Filed herewith.
31.2	Rule 13a-14(a)/15d-14(a) certification of Alberto Fornaro.	Filed herewith.
31.3	Rule 13a-14(a)/15d-14(a) certification of Emily Picarello.	Filed herewith.
32	Section 1350 Certification.	Furnished herewith.
95.1	Mine Safety Disclosure	Filed herewith.
101 INS	Inline XBRL Instance Document.	The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101 SCH	Inline XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	Inline XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	Inline XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	Inline XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	Inline XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.
104	Cover Page Interactive Data File (the cover page interactive data file does not appear in Exhibit 104 because it's Inline XBRL tags are embedded within the Inline XBRL document).	Filed herewith.

63

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	NRG ENERGY, INC. (Registrant)
	/s/ MAURICIO GUTIERREZ
	Mauricio Gutierrez
	Chief Executive Officer (Principal Executive Officer)
	/s/ ALBERTO FORNARO
	Alberto Fornaro
	Chief Financial Officer (Principal Financial Officer)
	/s/ EMILY PICARELLO
	Emily Picarello
Date: May 6, 2022	Corporate Controller (Principal Accounting Officer)

64

EX-22.1

EXHIBIT 22.1

LIST OF GUARANTOR SUBSIDIARIES

The following subsidiaries of NRG Energy, Inc. were guarantors of the Company'soutstanding registered senior notes of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes:

ENTITY NAME	JURISDICTION
Ace Energy, Inc.	New York
Airtron, Inc.	Delaware
Allied Home Warranty GP LLC	Delaware
Allied Warranty LLC	Texas
Astoria Gas Turbine Power LLC	Delaware
AWHR America's Water Heater Rentals, L.L.C.	Delaware
BidURenergy, Inc.	New York
Bounce Energy, Inc.	Delaware
Cabrillo Power I LLC	Delaware
Cabrillo Power II LLC	Delaware
Carbon Management Solutions LLC	Delaware
Cirro Energy Services, Inc.	Texas
Cirro Group, Inc.	Texas
CPL Retail Energy L.P.	Delaware
Direct Energy Business Marketing, LLC	Delaware
Direct Energy Business, LLC	Delaware
Direct Energy Connected Home US Inc.	Delaware
Direct Energy GP, LLC	Delaware
Direct Energy HoldCo GP LLC	Delaware
Direct Energy Leasing, LLC	Delaware
Direct Energy Marketing Inc.	Delaware
Direct Energy Operations, LLC	Delaware
Direct Energy Services, LLC	Delaware
Direct Energy US Holdings Inc.	Delaware
Direct Energy, LP	Texas
Dunkirk Power LLC	Delaware
Eastern Sierra Energy Company LLC	California
El Segundo Power II LLC	Delaware
El Segundo Power, LLC	Delaware
Energy Alternatives Wholesale, LLC	Delaware
Energy Choice Solutions LLC	Texas
Energy Plus Holdings LLC	Delaware
Energy Plus Natural Gas LLC	Delaware
Energy Protection Insurance Company	Vermont
Everything Energy LLC	Delaware
First Choice Power, LLC	Texas
Forward Home Security, LLC	Texas

Gateway Energy Services Corporation	New York
GCP Funding Company, LLC	Delaware
Green Mountain Energy Company	Delaware
Gregory Partners, LLC	Delaware
Gregory Power Partners LLC	Delaware
Home Warranty Holdings Corp.	Delaware
Huntley Power LLC	Delaware
Independence Energy Alliance LLC	Delaware
Independence Energy Group LLC	Delaware
Independence Energy Natural Gas LLC	Delaware
Indian River Operations Inc.	Delaware
Indian River Power LLC	Delaware
Masters, Inc.	Maryland
Meriden Gas Turbines LLC	Delaware
NEO Corporation	Minnesota
New Genco GP, LLC	Delaware
Norwalk Power LLC	Delaware
NRG Advisory Services LLC	Delaware
NRG Affiliate Services Inc.	Delaware
NRG Arthur Kill Operations Inc.	Delaware
NRG Astoria Gas Turbine Operations Inc.	Delaware
NRG Business Services LLC	Delaware
NRG Cabrillo Power Operations Inc.	Delaware
NRG California Peaker Operations LLC	Delaware
NRG Cedar Bayou Development Company, LLC	Delaware
NRG Connected Home LLC	Delaware
NRG Construction LLC	Delaware
NRG Controllable Load Services LLC	Delaware
NRG Curtailment Solutions, Inc.	New York
NRG Development Company Inc.	Delaware
NRG Devon Operations Inc.	Delaware
NRG Dispatch Services LLC	Delaware
NRG Distributed Energy Resources Holdings LLC	Delaware
NRG Distributed Generation PR LLC	Delaware
NRG Dunkirk Operations Inc.	Delaware
NRG ECOKAP Holdings LLC	Delaware
NRG El Segundo Operations Inc.	Delaware
NRG Energy Labor Services LLC	Delaware
NRG Energy Services Group LLC	Delaware
NRG Energy Services LLC	Delaware
NRG Generation Holdings Inc.	Delaware
NRG Greenco LLC	Delaware
NRG Home & Business Solutions LLC	Delaware

NRG Home Services LLC	Texas
NRG Home Solutions LLC	Delaware
NRG Home Solutions Product LLC	Delaware
NRG Homer City Services LLC	Delaware
NRG HQ DG LLC	Delaware
NRG Huntley Operations Inc.	Delaware
NRG Identity Protect LLC	Delaware
NRG Ilion Limited Partnership	Delaware
NRG Ilion LP LLC	Delaware
NRG International LLC	Delaware
NRG Maintenance Services LLC	Delaware
NRG Mextrans Inc.	Delaware
NRG Middletown Operations Inc.	Delaware
NRG Montville Operations Inc.	Delaware
NRG North Central Operations Inc.	Delaware
NRG Norwalk Harbor Operations Inc.	Delaware
NRG Operating Services, Inc.	Delaware
NRG Oswego Harbor Power Operations Inc.	Delaware
NRG Portable Power LLC	Delaware
NRG Power Marketing LLC	Delaware
NRG Protects Inc. (IL)	Illinois
NRG Reliability Solutions LLC	Delaware
NRG Renter's Protection LLC	Delaware
NRG Retail LLC	Delaware
NRG Retail Northeast LLC	Delaware
NRG Rockford Acquisition LLC	Delaware
NRG Saguaro Operations Inc.	Delaware
NRG Security LLC	Delaware
NRG Services Corporation	Delaware
NRG SimplySmart Solutions LLC	Delaware
NRG South Central Operations Inc.	Delaware
NRG South Texas LP	Texas
NRG Texas Gregory LLC	Delaware
NRG Texas Holding Inc.	Delaware
NRG Texas LLC	Delaware
NRG Texas Power LLC	Delaware
NRG Warranty Services LLC	Delaware
NRG West Coast LLC	Delaware
NRG Western Affiliate Services Inc.	Delaware
Reliant Energy Northeast LLC	Delaware
Reliant Energy Power Supply, LLC	Delaware
Reliant Energy Retail Holdings, LLC	Delaware
Reliant Energy Retail Services, LLC	Delaware

RERH Holdings, LLC	Delaware
RSG Holding Corp.	Delaware
Saguaro Power LLC	Delaware
SGE Energy Sourcing, LLC	Delaware
SGE Texas Holdco, LLC	Texas
Somerset Operations Inc.	Delaware
Somerset Power LLC	Delaware
Stream Energy Columbia, LLC	Delaware
Stream Energy Delaware, LLC	Delaware
Stream Energy Illinois, LLC	Delaware
Stream Energy Maryland, LLC	Delaware
Stream Energy New Jersey, LLC	Delaware
Stream Energy New York, LLC	Delaware
Stream Energy Pennsylvania, LLC	Delaware
Stream Georgia Gas SPE, LLC	Georgia
Stream Ohio Gas & Electric, LLC	Ohio
Stream SPE GP, LLC	Texas
Stream SPE, Ltd.	Texas
Texas Genco GP, LLC	Texas
Texas Genco Holdings, Inc.	Texas
Texas Genco LP, LLC	Delaware
Texas Genco Services, LP	Texas
US Retailers LLC	Delaware
Vienna Operations Inc.	Delaware
Vienna Power LLC	Delaware
WCP (Generation) Holdings LLC	Delaware
West Coast Power LLC	Delaware
WTU Retail Energy L.P.	Delaware
XOOM Alberta Holdings, LLC	Delaware
XOOM British Columbia Holdings, LLC	Delaware
XOOM Energy California, LLC	California
XOOM Energy Connecticut, LLC	Connecticut
XOOM Energy Delaware, LLC	Delaware
XOOM Energy Georgia, LLC	Georgia
XOOM Energy Global Holdings, LLC	Delaware
XOOM Energy Illinois LLC	Illinois
XOOM Energy Indiana, LLC	Indiana
XOOM Energy Kentucky, LLC	Kentucky
XOOM Energy Maine, LLC	Maine
XOOM Energy Maryland, LLC	Maryland
XOOM Energy Massachusetts, LLC	Massachusetts
XOOM Energy Michigan, LLC	Michigan
XOOM Energy New Hampshire, LLC	New Hampshire

XOOM Energy New Jersey, LLC	New Jersey
XOOM Energy New York, LLC	New York
XOOM Energy Ohio, LLC	Ohio
XOOM Energy Pennsylvania, LLC	Pennsylvania
XOOM Energy Rhode Island, LLC	Rhode Island
XOOM Energy Texas, LLC	Texas
XOOM Energy Virginia, LLC	Virginia
XOOM Energy Washington D.C., LLC	District of Columbia
XOOM Energy, LLC	Delaware
XOOM Ontario Holdings, LLC	Delaware
XOOM Solar, LLC	Delaware

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Mauricio Gutierrez, certify that:

1.I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ MAURICIO GUTIERREZ

Mauricio Gutierrez

Chief Executive Officer

(Principal Executive Officer)

Date: May 6, 2022

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Alberto Fornaro, certify that:

1.I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ ALBERTO FORNARO

Alberto Fornaro

Chief Financial Officer

(Principal Financial Officer)

Date: May 6, 2022

EX-31.3

EXHIBIT 31.3

CERTIFICATION

I, Emily Picarello, certify that:

1.I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ EMILY PICARELLO

Emily Picarello

Corporate Controller

(Principal Accounting Officer)

Date: May 6, 2022

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of NRG Energy, Inc. on Form 10-Q for the quarter ended March 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer's knowledge:

(1)The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-Q.

Date: May 6, 2022

/s/ MAURICIO GUTIERREZ 

Mauricio Gutierrez

Chief Executive Officer

(Principal Executive Officer)

/s/ ALBERTO FORNARO

Alberto Fornaro

Chief Financial Officer

(Principal Financial Officer)

/s/ EMILY PICARELLO

Emily Picarello

Corporate Controller

(Principal Accounting Officer) 

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this Form 10-Q or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NRG Energy, Inc. and will be retained by NRG Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-95.1

EXHIBIT 95.1

Mine Safety Disclosure

Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K(17 CFR 229.104) contain reporting requirements regarding mine safety. The operation of our mine is subject to regulation by the federal Mine Safety and Health Administration, or MSHA, under the Federal Mine Safety and Health Act of 1977, or the Mine Act. Set forth below is the required information regarding certain mining safety and health matters for the three months ended March 31, 2022 for our facility. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the mine, (ii) the number of citations issued will vary from inspector-to-inspector and mine-to-mine, and (iii) citations and orders can be contested and appealed, and in that process, may be reduced in severity and amount, and are sometimes dismissed.

Mine or Operating Name/MSHA Identification Number	Section 104 S&S Citations	Section 104(b) Orders	Sections 104(d) Citations and Orders	Sections 110(b)(2) Violations	Section 107(a) Orders	Total Dollar Value of MSHA Assessments Proposed	Total Number of Mining Related Fatalities	Received Notice of Pattern of Violations Under Section 104(e)	Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)	Legal Actions Pending as Last Day of Period	Legal Actions Initiated During Period	Legal Actions Resolved During Period
Jewett Mine, Jewett, TX (4103164)	1	0	0	0	0	(a)	0	0	0	0	0	0
(a) The assessment of the penalty for the associated citation has not yet been received

XML

Cover - shares	3 Months Ended
	Mar. 31, 2022	Apr. 30, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
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	910 Louisiana Street
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	537-3000
Title of 12(b) Security	Common Stock, par value $0.01
Trading Symbol	NRG
Security Exchange Name	NYSE
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
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		237,283,560
Entity Central Index Key	0001013871
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q1

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Revenue
Revenue	$ 7,896	$ 8,091
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)	4,930	6,857
Depreciation and amortization	183	317
Selling, general and administrative costs	322	337
Provision for credit losses	25	611
Acquisition-related transaction and integration costs	8	42
Total operating costs and expenses	5,468	8,164
(Loss)/Gain on sale of assets	(3)	17
Operating Income/(Loss)	2,425	(56)
Other Income/(Expense)
Equity in (losses) of unconsolidated affiliates	(15)	(6)
Other income, net	0	22
Interest expense	(103)	(127)
Total other expense	(118)	(111)
Income/(Loss) Before Income Taxes	2,307	(167)
Income tax expense/(benefit)	571	(85)
Net Income/(Loss)	$ 1,736	$ (82)
Income/(loss) per Share
Weighted average number of common shares outstanding — basic (in shares)	242	245
Weighted average number of common shares outstanding — diluted (in shares)	242	245
Income/(loss) per Weighted Average Common Share — Basic (in usd per share)	$ 7.17	$ (0.33)
Income/(loss) per Weighted Average Common Share — Diluted (in usd per share)	$ 7.17	$ (0.33)

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Comprehensive Income [Abstract]
Net Income/(Loss)	$ 1,736	$ (82)
Other Comprehensive Income
Foreign currency translation adjustments	9	3
Defined benefit plans	(1)	0
Other comprehensive income	8	3
Comprehensive Income/(Loss)	$ 1,744	$ (79)

XML

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Current Assets
Cash and cash equivalents	$ 387	$ 250
Funds deposited by counterparties	2,570	845
Restricted cash	39	15
Accounts receivable, net	3,291	3,245
Uplift securitization proceeds receivable from ERCOT	689	689
Inventory	354	498
Derivative instruments	9,089	4,613
Cash collateral paid in support of energy risk management activities	9	291
Prepayments and other current assets	409	395
Total current assets	16,837	10,841
Property, plant and equipment, net	1,643	1,688
Other Assets
Equity investments in affiliates	151	157
Operating lease right-of-use assets, net	256	271
Goodwill	1,796	1,795
Intangible assets, net	2,391	2,511
Nuclear decommissioning trust fund	949	1,008
Derivative instruments	3,561	2,527
Deferred income taxes	1,638	2,155
Other non-current assets	255	229
Total other assets	10,997	10,653
Total Assets	29,477	23,182
Current Liabilities
Current portion of long-term debt and finance leases	4	4
Current portion of operating lease liabilities	82	81
Accounts payable	2,216	2,274
Derivative instruments	6,076	3,387
Cash collateral received in support of energy risk management activities	2,570	845
Accrued expenses and other current liabilities	1,285	1,324
Total current liabilities	12,233	7,915
Other Liabilities
Long-term debt and finance leases	8,026	7,966
Non-current operating lease liabilities	220	236
Nuclear decommissioning reserve	325	321
Nuclear decommissioning trust liability	602	666
Derivative instruments	1,977	1,412
Deferred income taxes	68	73
Other non-current liabilities	996	993
Total other liabilities	12,214	11,667
Total Liabilities	24,447	19,582
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,839,804 and 423,547,174 shares issued and 239,216,140 and 243,753,899 shares outstanding at March 31, 2022 and December 31, 2021, respectively	4	4
Additional paid-in-capital	8,433	8,531
Retained earnings	2,171	464
Treasury stock, at cost 184,623,664 and 179,793,275 shares at March 31, 2022 and December 31, 2021, respectively	(5,460)	(5,273)
Accumulated other comprehensive loss	(118)	(126)
Total Stockholders' Equity	5,030	3,600
Total Liabilities and Stockholders' Equity	$ 29,477	$ 23,182

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Common stock, par or 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)	423,839,804	423,547,174
Common stock, shares outstanding (in shares)	239,216,140	243,753,899
Treasury stock, shares (in shares)	184,623,664	179,793,275

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Cash Flows from Operating Activities
Net Income/(Loss)	$ 1,736	$ (82)
Adjustments to reconcile net income/(loss) to cash provided by operating activities:
Distributions from and equity in losses of unconsolidated affiliates	18	17
Depreciation and amortization	183	317
Accretion of asset retirement obligations	7	3
Provision for credit losses	25	611
Amortization of nuclear fuel	14	13
Amortization of financing costs and debt discounts	6	11
Amortization of in-the-money contracts and emissions allowances	147	7
Amortization of unearned equity compensation	6	4
Net gain on sale and disposal of assets	(6)	(18)
Changes in derivative instruments	(2,816)	(902)
Changes in deferred income taxes and liability for uncertain tax benefits	527	(71)
Changes in collateral deposits in support of energy risk management activities	2,007	1
Changes in nuclear decommissioning trust liability	(7)	15
Changes in other working capital	(171)	(843)
Cash provided/(used) by operating activities	1,676	(917)
Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets, net of cash acquired	(26)	(3,482)
Capital expenditures	(60)	(63)
Net purchases of emission allowances	(18)	(5)
Investments in nuclear decommissioning trust fund securities	(151)	(129)
Proceeds from the sale of nuclear decommissioning trust fund securities	161	118
Proceeds from sale of assets, net of cash disposed	14	197
Cash used by investing activities	(80)	(3,364)
Cash Flows from Financing Activities
Payments of dividends to common stockholders	(85)	(80)
Payments for share repurchase activity	(188)	(9)
Net receipts from settlement of acquired derivatives that include financing elements	561	190
Net proceeds of Revolving Credit Facility and Receivables Securitization Facilities	0	825
Repayments of long-term debt and finance leases	(1)	(1)
Payments of debt issuance costs	0	(2)
Proceeds from issuance of common stock	0	1
Net Cash Provided by Financing Activities	287	924
Effect of exchange rate changes on cash and cash equivalents	3	1
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	1,886	(3,356)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,110	3,930
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$ 2,996	$ 574

XML

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions		Total	Cumulative Effect, Period of Adoption, Adjustment	Common Stock	Additional Paid-In Capital	Additional Paid-In Capital Cumulative Effect, Period of Adoption, Adjustment	Retained Earnings	Retained Earnings Cumulative Effect, Period of Adoption, Adjustment	Treasury Stock	Accumulated Other Comprehensive Loss
Beginning balance at Dec. 31, 2020		$ 1,680		$ 4	$ 8,517		$ (1,403)		$ (5,232)	$ (206)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income		(82)					(82)
Other comprehensive income (loss)		3								3
Equity-based awards activity, net	[1]	(5)			(5)
Issuance of common stock		1			1
Common stock dividends and dividend equivalents declared	[2]	(80)					(80)
Ending balance at Mar. 31, 2021		1,517		4	8,513		(1,565)		(5,232)	(203)
Beginning balance at Dec. 31, 2021		3,600	$ (43)	4	8,531	$ (100)	464	$ 57	(5,273)	(126)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net (loss) income		1,736					1,736
Other comprehensive income (loss)		8								8
Share repurchases		(187)							(187)
Equity-based awards activity, net	[1]	2			2
Common stock dividends and dividend equivalents declared	[2]	(86)					(86)
Ending balance at Mar. 31, 2022		$ 5,030		$ 4	$ 8,433		$ 2,171		$ (5,460)	$ (118)

[1] Includes $(6) million and $(9) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended March 31, 2022 and 2021, respectively

[2] Dividends per common share were $0.35 and $0.325 for the quarters ended March 31, 2022 and 2021, respectively

XML

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares shares in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Stockholders' Equity [Abstract]
Shares purchased for tax withholding obligation (in shares)	(6)	(9)
Dividends per common share (in usd per share)	$ 0.35	$ 0.325

XML

Nature of Business and Basis of Presentation

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Business and Basis of Presentation

Nature of Business and Basis of Presentation

General

NRG Energy, Inc., or NRG or the Company, is a consumer services company built on dynamic retail brands. NRG brings the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. NRG sells power, natural gas, home and power services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy. The Company has a customer base that includes approximately 6 million Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of generation.

During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released, leading the Company to announce the near-term retirement of approximately 1,600 MW of its PJM coal generating assets in June 2022. On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of those assets, Indian River Unit 4. On August 27, 2021 the Company notified PJM that it would continue operations at Indian River Unit 4 until the reliability upgrades identified by PJM were completed, provided that the unit receives a satisfactory and compensatory reliability must run arrangement. Accordingly, NRG filed a cost based RMR rate schedule at FERC on April 1, 2022, seeking a June 1, 2022 effective date. The Company is continuing to evaluate the viability of the remaining PJM generating assets.

The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus.

The Company's business is segmented as follows:

•Texas, which includes all activity related to customer, plant and market operations in Texas, other than Cottonwood;

•East, which includes all activity related to customer, plant and market operations in the East;

•West/Services/Other, which includes the following assets and activities: (i) all activity related to plant and market operations in the West and Canada, (ii) the Services businesses (iii) activity related to the Cottonwood facility, (iv) the remaining renewables activity, including the Company’s equity method investment in Ivanpah Master Holdings, LLC, and (v) activity related to the Company’s equity method investment for the Gladstone power plant in Australia; and

•Corporate activities.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's 2021 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of March 31, 2022, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three months ended March 31, 2022 and 2021.

Use of Estimates

The preparation of financial statements in conformity with GAAP 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.

Reclassifications

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

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Other Balance Sheet Information

The following table presents the accumulated depreciation included in property, plant and equipment, net and accumulated amortization included in intangible assets, net:

(In millions)	March 31, 2022		December 31, 2021
Property, plant and equipment accumulated depreciation	$	1,419	$	1,308
Intangible assets accumulated amortization	1,867		1,636

Credit Losses

Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues a provision 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 following table represents the activity in the allowance for credit losses for the three months ended March 31, 2022 and 2021:

	Three months ended March 31,
(In millions)	2022		2021
Beginning balance	$	683	$	67
Acquired balance from Direct Energy	—		112
Provision for credit losses	25		611
Write-offs	(50)		(48)
Recoveries collected	8		7
Ending balance	$	666	$	749

The decrease in the provision for credit losses during the three months ended March 31, 2022, compared to the same period in 2021 was primarily due to the impacts of Winter Storm Uri during the prior year on bilateral finance hedging risk of $393 million, counterparty credit risk of $109 million and ERCOT default shortfall payments of $83 million.

Cash and Cash Equivalents, Funds Deposited by Counterparties and 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:

(In millions)	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	387	$	250
Funds deposited by counterparties	2,570		845
Restricted cash	39		15
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	2,996	$	1,110

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties related to NRG's hedging program. The increase in funds deposited by counterparties is driven by the significant increase in forward positions as a result of increases in natural gas and power prices. Though some amounts are segregated into separate accounts, not all funds are contractually restricted. Based on the Company's intention, these funds are not available for the payment of general corporate obligations; however, they are available for liquidity management. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the 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.

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

Winter Storm Uri Uplift Securitization Proceeds

The Texas Legislature passed House Bill ("HB") 4492 in May of 2021 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.

In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement methodology. The Company accounted for the proceeds it will receive by analogy to the contribution model within ASC 958-605, Not-for-Profit Entities- Revenue Recognition and the grant model within IAS 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to cost of operations within its consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company expects to receive proceeds of $689 million from ERCOT in the second quarter of 2022 which is reflected as a receivable on its consolidated balance sheets.

Recent Accounting Developments - Guidance Adopted in 2022

ASU 2020-06 — In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40), or ASU 2020-06. The guidance in ASU 2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock. In addition, ASU 2020-06 improves and amends the related earnings per share guidance. The Company adopted this standard on January 1, 2022 using the modified retrospective approach. As a result of the provisions of the amended guidance, the Company recorded a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings and a $14 million decrease to long-term deferred tax liabilities. The adoption of ASU 2020-06 did not have a material impact on the Company's statement of operations, statement of cash flow or earnings per share amounts.

XML

Revenue Recognition

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenue Recognition

Revenue Recognition

Performance Obligations

As of March 31, 2022, estimated future fixed fee performance obligations are $151 million for the remaining nine months of fiscal year 2022, and $52 million and $1 million for the fiscal years 2023 and 2024, respectively. These performance obligations are for cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non-performance.

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three months ended March 31, 2022 and 2021:

	Three months ended March 31, 2022
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,289	$	675	$	697	$	—	$	2,661
Business	663		3,846		400		—		4,909
Total retail revenue	1,952		4,521		1,097		—		7,570
Energy revenue(b)	15		204		54		5		278
Capacity revenue(b)	—		115		1		—		116
Mark-to-market for economic hedging activities(c)	(2)		(130)		(18)		17		(133)
Contract amortization	—		(9)		—		—		(9)
Other revenue(b)	58		17		4		(5)		74
Total revenue	2,023		4,718		1,138		17		7,896
Less: Revenues accounted for under topics other than 606 and 815	—		(9)		11		—		2
Less: Realized and unrealized ASC 815 revenue	(7)		(66)		(42)		20		(95)
Total revenue from contracts with customers	$	2,030	$	4,793	$	1,169	$	(3)	$	7,989
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	45	$	(20)	$	4	$	29
Capacity revenue	—		13		—		—		13
Other revenue	(5)		6		(4)		(1)		(4)
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

	Three months ended March 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,333	$	584	$	554	$	—	$	2,471
Business	781		2,629		281		—		3,691
Total retail revenue	2,114		3,213		835		—		6,162
Energy revenue(c)	285		126		70		1		482
Capacity revenue(c)	—		141		14		—		155
Mark-to-market for economic hedging activities(d)	(1)		(4)		(28)		1		(32)
Other revenue(b)(c)	1,304		19		4		(3)		1,324
Total revenue	3,702		3,495		895		(1)		8,091
Less: Revenues accounted for under topics other than 606 and 815	—		—		2		—		2
Less: Realized and unrealized ASC 815 revenue	93		99		(34)		2		160
Total revenue from contracts with customers	$	3,609	$	3,396	$	927	$	(3)	$	7,929
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.2 billion driven by high pricing during Winter Storm Uri
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	60	$	(4)	$	2	$	58
Capacity revenue	—		37		—		—		37
Other revenue	94		6		(2)		(1)		97
(d) 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 March 31, 2022 and December 31, 2021:

(In millions)	March 31, 2022		December 31, 2021
Deferred customer acquisition costs	$	111	$	133
Accounts receivable, net - Contracts with customers	3,091		3,057
Accounts receivable, net - Derivative instruments	197		182
Accounts receivable, net - Affiliate	3		6
Total accounts receivable, net	$	3,291	$	3,245
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,237	$	1,574
Deferred revenues(a)	177		227

(a) Deferred revenues from contracts with customers for the three months ended March 31, 2022 and the year ended December 31, 2021 were approximately $169 million and $224 million, respectively

The revenue recognized from contracts with customers during the three months ended March 31, 2022 and 2021 relating to the deferred revenue balance at the beginning of each period was $117 million and $23 million, respectively. The change in deferred revenue balances during the three months ended March 31, 2022 and 2021 was primarily due to the usage of customer bill credits by certain C&I customers, which were as a result of power pricing during Winter Storm Uri and a significant increase in customer count as a result of the Direct Energy acquisition.

XML

Acquisitions and Dispositions

3 Months Ended

Mar. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Acquisitions and Dispositions

Acquisitions and Dispositions

Acquisitions

2021 Acquisition of Direct Energy

On January 5, 2021, the Company acquired all of the issued and outstanding common shares of Direct Energy, which had been a North American subsidiary of Centrica. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition 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 and total purchase price adjustment of $99 million, resulting in an adjusted purchase price of $3.724 billion. For additional information refer to Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Company's 2021 Form 10-K.

Dispositions

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

XML

Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

Fair Value of Financial Instruments For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts payable, and cash collateral paid and received in support of energy risk management activities, the carrying amounts approximate fair values because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

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

	March 31, 2022				December 31, 2021
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Convertible Senior Notes	$	575	$	633	$	518	$	677
Other long-term debt, including current portion	7,523		7,128		7,522		7,650
Total long-term debt, including current portion(a)	$	8,098	$	7,761	$	8,040	$	8,327

(a) Excludes deferred financing costs, which are recorded as a reduction to long-term debt in 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.

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 condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:

	March 31, 2022
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	17	$	—	$	17	$	—
Nuclear trust fund investments:
Cash and cash equivalents	17		17		—		—
U.S. government and federal agency obligations	106		105		1		—
Federal agency mortgage-backed securities	104		—		104		—
Commercial mortgage-backed securities	41		—		41		—
Corporate debt securities	116		—		116		—
Equity securities	471		471		—		—
Foreign government fixed income securities	2		—		2		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	12,650		2,528		9,403		719
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	92
Equity securities (classified within other non-current assets)	7
Total assets	$	13,624	$	3,122	$	9,684	$	719
Derivative liabilities:
Foreign exchange contracts	$	4	$	—	$	4	$	—
Commodity contracts	8,049		1,173		6,685		191
Total liabilities	$	8,053	$	1,173	$	6,689	$	191

	December 31, 2021
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	32	$	15	$	17	$	—
Nuclear trust fund investments:
Cash and cash equivalents	33		33		—		—
U.S. government and federal agency obligations	112		111		1		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	44		—		44		—
Corporate debt securities	122		—		122		—
Equity securities	494		494		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Foreign exchange contracts	1		—		1		—
Commodity contracts	7,139		981		5,701		457
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	99
Equity securities (classified within other non-current assets)	7
Total assets	$	8,188	$	1,635	$	5,990	$	457
Derivative liabilities:
Foreign exchange contracts	$	1	$	—	$	1	$	—
Commodity contracts	4,798		626		4,008		164
Total liabilities	$	4,799	$	626	$	4,009	$	164

The following table reconciles, for the three months ended March 31, 2022 and 2021, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs:

	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Derivatives(a)
(In millions)	Three months ended March 31, 2022		Three months ended March 31, 2021
Beginning balance	$	293	$	(16)
Contracts added from Direct Energy acquisition	—		(15)
Total gains realized/unrealized — included in earnings	166		180
Purchases	23		20
Transfers into Level 3(b)	53		4
Transfers out of Level 3(b)	(7)		(14)
Ending balance	$	528	$	159
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 period end	$	237	$	146

(a)Consists of derivative 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 in/out are with Level 2

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

Derivative Fair Value Measurements

A portion of NRG'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. The remainder of the assets and liabilities represent 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 the observable market data with similar characteristics. As of March 31, 2022, contracts valued with prices provided by models and other valuation techniques make up 6% of derivative assets and 2% of derivative liabilities.

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

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of March 31, 2022 and December 31, 2021:

	March 31, 2022
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	$	676	$	153	Discounted Cash Flow	Forward Market Price (per MWh)	$	6	$	278	$	47
FTRs	43		38		Discounted Cash Flow	Auction Prices (per MWh)	(105)		43		0
	$	719	$	191

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

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of March 31, 2022 and December 31, 2021:

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

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 is calculated based on published default probabilities. As of March 31, 2022, the credit reserve resulted in a $5 million decrease primarily within cost of operations. As of December 31, 2021, the credit reserve resulted in a $11 million decrease primarily within cost of operations.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2021 Form 10-K, the following is a discussion of the concentration of credit risk for the Company's contractual obligations. 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. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, as well as retail customer credit risk through its retail load activities.

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2021 Form 10-K. As of March 31, 2022, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $3.2 billion and NRG held collateral (cash and letters of credit) against those positions of $1.5 billion, resulting in a net exposure of $1.8 billion. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 82% of the Company's exposure before collateral is expected to roll off by the end of 2023. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.

	Net Exposure(a)(b)
Category by Industry Sector	(% of Total)
Utilities, energy merchants, marketers and other	59	%
Financial institutions	41
Total as of March 31, 2022	100	%

	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	59	%
Non-investment grade/non-rated	41
Total as of March 31, 2022	100	%

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

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

The Company currently has no exposure to wholesale counterparties in excess of 10% of total net exposure discussed above as of March 31, 2022. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

During the first quarter of 2021, during Winter Storm Uri, the Company experienced a nonperformance by a counterparty in one of its bilateral financial hedging transactions, resulting in exposure of $393 million. The Company is pursuing all means available to enforce its obligations under this transaction but, given the size of the exposure and the counterparty filing for Chapter 11 bankruptcy protection, cannot determine with certainty what the amount of its ultimate recovery will be. The full exposure was recorded as a provision for credit losses as of March 31, 2021.

RTOs and ISOs

The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, whereas in the case of ERCOT, it is approved by the PUCT, and whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO to the Ontario Energy Board. These ISOs may include 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 the overall market and are excluded from the above exposures.

Exchange Traded Transactions

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

Long-Term Contracts

Counterparty credit exposure described above excludes credit risk exposure under certain long-term contracts, primarily solar PPAs. As external sources or observable market quotes are not always 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 March 31, 2022, aggregate credit risk exposure managed by NRG to these counterparties was approximately $1.2 billion for the next five years.

Retail Customer Credit Risk

The Company is exposed to retail credit risk through the Company's retail electricity and gas providers, which serve Home and Business customers. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both non-payment 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 March 31, 2022, the Company's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. 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.

XML

Nuclear Decommissioning Trust Fund

3 Months Ended

Mar. 31, 2022

Regulated Operations [Abstract]

Nuclear Decommissioning Trust Fund

Nuclear Decommissioning Trust Fund

NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its 44% interest in STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, 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 OCI, 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 March 31, 2022							As of December 31, 2021
(In millions, except maturities)	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	$	17	$	—	$	—	—	$	33	$	—	$	—	—
U.S. government and federal agency obligations	106		2		4		10	112		5		1		10
Federal agency mortgage-backed securities	104		1		3		25	100		2		—		25
Commercial mortgage-backed securities	41		—		2		27	44		1		—		27
Corporate debt securities	116		2		5		14	122		7		1		14
Equity securities	563		424		—		—	593		456		—		—
Foreign government fixed income securities	2		—		—		19	4		—		—		13
Total	$	949	$	429	$	14		$	1,008	$	471	$	2

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

	Three months ended March 31,
(In millions)	2022		2021
Realized gains	$	1	$	3
Realized losses	(4)		(2)
Proceeds from sale of securities	161		118

XML

Accounting for Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of March 31, 2022, NRG had energy-related derivative instruments extending through 2036. The Company marks these derivatives to market through the statement of operations. NRG has executed energy-related contracts extending through 2038 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

Foreign Exchange Contracts

NRG is exposed to changes in foreign currency primarily associated with the purchase of USD denominated natural gas for its Canadian business. In order to manage the Company's foreign exchange risk, NRG entered into foreign exchange contracts. As of March 31, 2022, NRG had foreign exchange contracts extending through 2025. The Company marks these derivatives to market through the statement of operations.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of March 31, 2022 and December 31, 2021. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.

		Total Volume (In millions)
Category	Units	March 31, 2022		December 31, 2021
Emissions	Short Ton	—		1
Renewable Energy Certificates	Certificates	13		13
Coal	Short Ton	14		19
Natural Gas	MMBtu	811		813
Oil	Barrels	—		1
Power	MWh	175		185
Foreign Exchange	Dollars	$	264	$	279

Fair Value of Derivative Instruments

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

	Fair Value
	Derivative Assets				Derivative Liabilities
(In millions)	March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Foreign exchange contracts - current	$	—	$	—	$	2	$	1
Foreign exchange contracts - long-term	—		1		2		—
Commodity contracts - current	9,089		4,613		6,074		3,386
Commodity contracts - long-term	3,561		2,526		1,975		1,412
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	12,650	$	7,140	$	8,053	$	4,799

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 of 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 March 31, 2022
Foreign exchange contracts:
Derivative liabilities	$	(4)	$	—	$	—	$	(4)
Commodity contracts:
Derivative assets	$	12,650	$	(7,482)	$	(2,631)	$	2,537
Derivative liabilities	(8,049)		7,482		41		(526)
Total commodity contracts	$	4,601	$	—	$	(2,590)	$	2,011
Total derivative instruments	$	4,597	$	—	$	(2,590)	$	2,007

	Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
As of December 31, 2021
Foreign exchange contracts:
Derivative assets	$	1	$	(1)	$	—	$	—
Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	$	—	$	—	$	—	$	—
Commodity contracts:
Derivative assets	$	7,139	$	(4,440)	$	(831)	$	1,868
Derivative liabilities	(4,798)		4,440		17		(341)
Total commodity contracts	$	2,341	$	—	$	(814)	$	1,527
Total derivative instruments	$	2,341	$	—	$	(814)	$	1,527

Impact of Derivative Instruments on the Statements of Operations

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

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

(In millions)	Three months ended March 31,
Unrealized mark-to-market results	2022		2021
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(408)	$	17
Reversal of acquired (gain)/loss positions related to economic hedges	(60)		145
Net unrealized gains on open positions related to economic hedges	2,745		559
Total unrealized mark-to-market gains for economic hedging activities	2,277		721
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	1		(7)
Net unrealized (losses)/gains on open positions related to trading activity	(15)		11
Total unrealized mark-to-market (losses)/gains for trading activity	(14)		4
Total unrealized gains	$	2,263	$	725

	Three months ended March 31,
(In millions)	2022		2021
Unrealized (losses) included in revenues - commodities	$	(147)	$	(28)
Unrealized gains included in cost of operations - commodities	2,414		755
Unrealized (losses) included in cost of operations - foreign exchange	(4)		(2)
Total impact to statement of operations - commodities	$	2,263	$	725

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

For the three months ended March 31, 2022, the $2.7 billion unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward positions as a result of increases in natural gas and power prices.

For the three months ended March 31, 2021, the $559 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward positions due to increases in ERCOT power prices and ERCOT heat rate expansion.

Credit Risk Related Contingent Features

Certain of the Company's trading agreements contain provisions that entitle the counterparty to demand that the Company post additional collateral if the counterparty determines that there has been deterioration in the Company's credit quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if there were a downgrade in the Company's credit rating. The collateral potentially required for all contracts with adequate assurance clauses that are in a net liability position as of March 31, 2022 was $790 million. The Company is also party to certain marginable agreements under which it has net liability position, but the counterparty has not called for the collateral due, which was approximately $56 million as of March 31, 2022. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $26 million of additional collateral would be required for all contracts with credit rating contingent features as of March 31, 2022.

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

XML

Long-term Debt and Finance Leases

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Long-term Debt and Finance Leases

Long-term Debt and Finance Leases

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

(In millions, except rates)	March 31, 2022		December 31, 2021		Interest rate %
Recourse debt:
Senior Notes, due 2027	$	375	$	375	6.625
Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	733		733		5.250
Senior Notes, due 2029	500		500		3.375
Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	1,100		1,100		3.875
Convertible Senior Notes, due 2048(a)	575		575		2.750
Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2025	500		500		2.000
Senior Secured First Lien Notes, due 2027	900		900		2.450
Senior Secured First Lien Notes, due 2029	500		500		4.450
Tax-exempt bonds	466		466		1.250 - 4.750
Subtotal recourse debt	8,100		8,100
Finance leases	13		13		various
Subtotal long-term debt and finance leases (including current maturities)	8,113		8,113
Less current maturities	(4)		(4)
Less debt issuance costs	(81)		(83)
Discounts	(2)		(60)
Total long-term debt and finance leases	$	8,026	$	7,966

(a)As of the ex-dividend date of April 29, 2022, the Convertible Senior Notes were convertible at a price of 44.15, which is equivalent to a conversion rate of approximately 22.6516 shares of common stock per $1,000 principal amount.

2048 Convertible Senior Notes

Accounting for Convertible Senior Notes — Upon issuance, the Convertible Senior Notes were separated into liability and equity components for accounting purposes. The carrying amounts of the liability component was initially calculated by measuring the fair value of similar liabilities that do not have an associated convertible feature. The carrying amount of the equity component representing the conversion option was determined by deducting the fair value of the liability component from the par value of the Convertible Senior Notes. This difference represented the debt discount that was amortized to interest expense over seven years, which was determined to be the expected life of the Convertible Senior Notes, using the effective interest rate method. The equity component was recorded in additional paid-in capital and was not remeasured as it continued to meet the conditions for equity classification.

Following the adoption of ASU 2020-06 as of January 1, 2022, the Company no longer records the conversion feature of its convertible senior notes in equity. Instead, the Company combined the previously separated equity component with the liability component, which together is now classified as debt, thereby eliminating the subsequent amortization of the debt discount as interest expense. As a result of the provisions of the amended guidance, the Company recorded a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings and a $14 million decrease to long-term deferred tax liabilities. For more information on the adoption of ASU 2020-06, refer to Note 2, Summary of Significant Accounting Policies.

Modification to Convertible Senior Notes — On February 22, 2022, the Company irrevocably elected to eliminate the right to settle conversions only in shares of the Company's common stock, such that any conversion after such date, the Company will pay cash per $1,000 principal amount and will settle in cash or a combination of cash and the Company's common stock for the remainder, if any, of the Company’s conversion obligation in excess of the aggregate principal amount.

Convertible Senior Notes Features — As of March 31, 2022, the Convertible Senior Notes were convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock at a price of $44.53 per common share, which is equivalent to a conversion rate of approximately 22.4563 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The Convertible Senior Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The Convertible Senior notes are convertible at the option of the holders under certain circumstances. Prior to the close of business on the business day immediately preceding December 1, 2024, the Convertible

Senior Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:

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

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

The following table details the interest expense recorded in connection with the Convertible Senior Notes, due 2048:

($ In millions)	For the three months ended March 31, 2022			For the three months ended March 31, 2021
Contractual interest expense	$	4		$	4
Amortization of discount and deferred finance costs	—			4
Total	$	4		$	8
Effective Interest Rate	0.76		%	1.32		%

Repurchase Facility

On February 9, 2022, the Company entered into amendments to its existing Repurchase Facility to, among other things, (i) increase the size of the facility from $75 million to $150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate. The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%. As of March 31, 2022, there were no outstanding borrowings.

Bilateral Letter of Credit Facilities

On April 29, 2022, the Company increased the size of the facilities by $100 million to provide additional liquidity, allowing for the issuance of up to $575 million of letters of credit.

XML

Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs

3 Months Ended

Mar. 31, 2022

Variable Interest Entities Disclosure [Abstract]

Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs

Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs

Entities that are not Consolidated

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

Variable Interest Entities that are Consolidated

The Company has a controlling financial interest that has been identified as a VIE under ASC 810 in NRG Receivables LLC, which has entered into financing transactions related to the Receivables Facility as further described in Note 13, Long-term Debt and Finance Leases, to the Company’s 2021 Form 10-K.

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

(In millions)	March 31, 2022		December 31, 2021
Accounts receivable and Other current assets	$	573	$	939
Current liabilities	78		78
Net assets	$	495	$	861

XML

Changes in Capital Structure

3 Months Ended

Mar. 31, 2022

Equity [Abstract]

Changes in Capital Structure

Changes in Capital Structure

As of March 31, 2022 and December 31, 2021, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:

	Issued	Treasury	Outstanding
Balance as of December 31, 2021	423,547,174	(179,793,275)	243,753,899
Shares issued under LTIPs	292,630	—	292,630
Shares repurchased	—	(4,830,389)	(4,830,389)
Balance as of March 31, 2022	423,839,804	(184,623,664)	239,216,140
Shares issued under LTIPs	13,213	—	13,213
Shares issued under ESPP	—	68,941	68,941
Shares repurchased	—	(2,014,734)	(2,014,734)
Balance as of April 30, 2022	423,853,017	(186,569,457)	237,283,560

Share Repurchases

The Company adopted in the fourth quarter of 2019 a long-term capital allocation policy that targets allocating 50% of cash available for allocation generated each year to growth investments and 50% to be returned to shareholders. The return of capital to shareholders is expected to be completed through the increased dividend discussed below, supplemented by share repurchases. On December 6, 2021 the Company announced that the Board of Directors has authorized $1 billion for share repurchases, as part of NRG’s capital allocation program. During 2021, $44 million of share repurchases were completed under this authorization. During the first quarter of 2022, the Company completed $187 million of share repurchases under the plan at an average price of $38.66.

The following repurchases have been made during the three months ended March 31, 2022 and through April 30, 2022:

	Total number of shares and share equivalents purchased	Average price paid per share and share equivalent	Amounts paid for shares and share equivalents purchased (in millions)
2022 repurchases
Repurchases(a)	4,830,389		$	187
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	131,899		6
Total Share Repurchases during the three months ended March 31, 2022	4,962,288	$38.78	193
Repurchases made during April 2022	2,014,734		$	76
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	5,465		—
Total Share Repurchases January 1, 2022 through April 30, 2022	6,982,487	$38.55	$	269

(a)Includes $10 million accrued as of March 31, 2022

(b)NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management. The average price per equivalent shares withheld was $43.03 and $39.19 for the three months ended March 31, 2022 and for April 2022, respectively

Employee Stock Purchase Plan

In March 2019, the Company reopened participation in the ESPP, which allows eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of NRG common stock at the lesser of 95% of its market value on the offering date or 95% of the fair market value on the exercise date. An offering date occurs each April 1 and October 1. An exercise date occurs each September 30 and March 31.

NRG Common Stock Dividends

During the first quarter of 2022, NRG increased the annual dividend to $1.40 from $1.30 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.35 per share was paid on the Company's common stock during the three months ended March 31, 2022. On April 20, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, payable on May 16, 2022 to stockholders of record as of May 2, 2022.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

XML

Income/(loss) Per Share

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Income/(loss) Per Share

Income/(loss) Per Share

Basic income/(loss) per common share is computed by dividing net income/(loss) by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted income per share is computed in a manner consistent with that of basic income per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The outstanding relative performance stock units, non-vested restricted stock units, market stock units, and non-qualified stock options are not considered outstanding for purposes of computing basic income per share. However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method for periods when we have net income. The Convertible Senior Notes are convertible, under certain circumstances, into cash or combination of cash and Company’s common stock. Prior to adoption of ASU 2020-06, there was no dilutive effect for the Convertible Senior Notes due to the Company’s expectation to settle the liability in cash. Upon adoption of ASU 2020-06, on January 1, 2022, the Company is including the potential share settlements, if any, in the denominator for purposes of computing diluted income per share under the if converted method for periods when we have net income. The potential shares settlements are calculated as the excess of the Company's conversion obligation over the aggregate principal amount (which will be settled in cash), divided by the average share price for the period. For the period ended March 31, 2022, there was no dilutive effect for the Convertible Senior Notes since there were no potential share settlements for that period.

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

	Three months ended March 31,
(In millions, except per share data)	2022		2021
Basic income/(loss) per share:
Net income/(loss)	$	1,736	$	(82)
Weighted average number of common shares outstanding - basic	242		245
Income/(loss) per weighted average common share — basic	$	7.17	$	(0.33)
Diluted income/(loss) per share:
Net income/(loss)	$	1,736	$	(82)
Weighted average number of common shares outstanding - basic	242		245
Weighted average number of common shares outstanding - dilutive	242		245
Income/(loss) per weighted average common share — diluted	$	7.17	$	(0.33)

As of March 31, 2022, the Company had 1 million outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted income per share. As of March 31, 2021, the Company had 1 million shares of outstanding equity instruments that were not included in the computation of the Company’s diluted loss per share since the Company was in a loss position for the period.

XML

Segment Reporting

3 Months Ended

Mar. 31, 2022

Segment Reporting [Abstract]

Segment Reporting

Segment Reporting

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

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and allocation of capital, as well as net income/(loss).

	Three months ended March 31, 2022
(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Revenue	$	2,023	$	4,718	$	1,138	$	—	$	17	$	7,896
Depreciation and amortization	76		78		21		8		—		183
Loss on sale of assets	—		—		(1)		(2)		—		(3)
Equity in (losses) of unconsolidated affiliates	(1)		—		(14)		—		—		(15)
Income/(loss) before income taxes	773		1,541		124		(131)		—		2,307
Net income/(loss)	$	773	$	1,541	$	125	$	(703)	$	—	$	1,736

	Three months ended March 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Revenue	$	3,702	$	3,495	$	895	$	—	$	(1)	$	8,091
Depreciation and amortization	77		206		27		7		—		317
Gain on sale of assets	—		—		17		—		—		17
Equity in (losses) of unconsolidated affiliates	(1)		—		(5)		—		—		(6)
(Loss)/income before income taxes	(433)		356		79		(169)		—		(167)
Net (loss)/income	$	(433)	$	356	$	74	$	(79)	$	—	$	(82)

XML

Income Taxes

3 Months Ended

Mar. 31, 2022

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:

	Three months ended March 31,
(In millions, except rates)	2022			2021
Income before income taxes	$	2,307		$	(167)
Income tax expense/(benefit)	571			(85)
Effective income tax rate	24.8		%	50.9		%

For the three months ended March 31, 2022, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense. For the same periods in 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax benefits and one-time tax benefits, as a result of the acquisition of Direct Energy, on the revaluation of state deferred tax assets, NOLs, and valuation allowance.

Uncertain Tax Benefits

As of March 31, 2022, NRG had a non-current tax liability of $19 million for uncertain tax benefits from positions taken on various federal and state income tax returns and accrued interest. For the three months ended March 31, 2022, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of March 31, 2022, NRG had cumulative interest and penalties related to these uncertain tax benefits of $1 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia and Canada. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2017. With few exceptions, state and local income tax examinations are no longer open for years prior to 2013.

XML

Related Party Transactions

3 Months Ended

Mar. 31, 2022

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

NRG provides services to some of its related parties, who are accounted for as equity method investments, under operations and maintenance agreements. Fees for the services under these agreements include recovery of NRG's costs of operating the plants. Certain agreements also include fees for administrative service, a base monthly fee, profit margin and/or annual incentive bonus.

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

	Three months ended March 31,
(In millions)	2022		2021
Revenues from Related Parties Included in Revenue
Gladstone	$	1	$	1
Ivanpah(a)	13		12
Midway-Sunset	2		2
Total	$	16	$	15

(a)Also includes fees under project management agreements with each project company

XML

Commitments and Contingencies

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Commitments

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of property and assets owned by NRG and the guarantors of its senior debt. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedges. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a claim under the first lien program. As of March 31, 2022, hedges under the first lien program were out-of-the-money for NRG on a counterparty aggregate basis.

Contingencies

The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records accruals for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, the Company has established an adequate accrual for the applicable legal matters, including regulatory and environmental matters as further discussed in Note 16, Regulatory Matters, and Note 17, Environmental Matters. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded accruals and that such differences could be material.

In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

Environmental Lawsuits

Sierra club et al. v. Midwest Generation LLC — In 2012, several environmental groups filed a complaint against Midwest Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in groundwater contamination. In June 2019, the IPCB found in an interim order that Midwest Generation violated the law because it had improperly handled coal ash at four facilities in Illinois and caused or allowed coal ash constituents to impact groundwater. On September 9, 2019, Midwest Generation filed a Motion to Reconsider numerous issues, which the court granted in part and denied in part on February 6, 2020. The IPCB will hold hearings to determine the appropriate relief. Midwest Generation has been working with the Illinois EPA to address the groundwater issues since 2010.

Consumer Lawsuits

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

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

XOOM Energy

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

Direct Energy

There are three putative class actions pending against Direct Energy: (1) Linda Stanley v. Direct Energy (S.D.N.Y Apr. 2019) - The parties mediated in June and agreed on a settlement. On November 16, 2021, the Court granted preliminary approval of the settlement. On April 5, 2022, the Court granted final approval of the settlement. However, it may take several months to determine the final payout amount; (2) Martin Forte v. Direct Energy (N.D.N.Y. Mar. 2017) - The Court recently granted Direct Energy's Motion for summary judgment effectively ending the matter at the district court level. It is likely that the plaintiff will appeal; however, it is unlikely the plaintiff will prevail; (3) Richard Schafer v. Direct Energy (W.D.N.Y. Dec.

2019; on appeal 2nd Cir. N.Y.) - The Court granted limited discovery that will end April 29, 2022. Summary judgment briefing is due on May 20, 2022.

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

There are two putative class actions pending against Direct Energy: (1) Holly Newman v. Direct Energy, LP (D. Md Sept 2021) - Direct Energy filed its Motion to Dismiss asserting the ruling in the Brittany Burk v. Direct Energy (S.D. Tex. Feb 2019) preempts the Plaintiff's ability to file suit based on the same facts; and (2) Matthew Dickson v. Direct Energy (N.D. Ohio Jan. 2018) - Direct Energy filed a Third-Party Petition against its vendor, Total Marketing Concepts, LLC, who placed voicemails without consent from Direct Energy and in violation of the parties’ agreement. The case was stayed pending the outcome of an appeal to the Sixth Circuit based on the unconstitutionality of the TCPA during the period from 2015-2020. The Sixth Circuit found the TCPA was in effect during that period and remanded the case back to the trial court. Direct Energy refiled its motions along with supplements. On March 25, 2022, the Court granted summary judgment in favor of Direct Energy and dismissed the case. The plaintiff is expected to appeal.

Winter Storm Uri Lawsuits

The Company has been named in certain property damage and wrongful death claims that have been filed in connection with Winter Storm Uri in its capacity as a generator and a retail electric provider. As a power generator, the Company is named in 161 cases with claims ranging from: wrongful death; personal injury only; property damage and personal injury; property damage only; and subrogation. As a retail electric provider, the Company is named in 27 lawsuits with similar claims: wrongful death; property damage only; personal injury only; and both personal injury and property damage. The power generators and retail electric providers are working together to file a handful of motions to dismiss that represent the breadth of the claims filed against them. These motions are due May 17, 2022. All of the lawsuits related to Winter Storm Uri are consolidated into a single multi-district litigation matter in Harris County District Court. The Company intends to vigorously defend these matters.

Indemnifications and Other Contractual Arrangements

Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against LaGen in the United States District Court for the Middle District of Louisiana. The plaintiffs claimed breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs sought damages for the alleged improper charges and a declaration as to which charges were proper under the contract. In February 2020, the court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. On March 17, 2020, plaintiffs filed a lawsuit in the Nineteenth Judicial District Court for the Parish of East Baton Rouge in Louisiana alleging substantially the same matters. On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.

XML

Regulatory Matters

3 Months Ended

Mar. 31, 2022

Regulatory Matters Disclosure [Abstract]

Regulatory Matters

Regulatory Matters

Environmental regulatory matters are discussed within Note 17, Environmental Matters.

NRG operates in a highly regulated industry and is subject to regulation by various federal, state and provincial agencies. As such, NRG is affected by regulatory developments at the federal, state and provincial levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail operations.

In addition to the regulatory proceeding noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

California Station Power — As the result of unfavorable final and non-appealable litigation, the Company accrued a liability associated with consumption of station power at the Company's Encina power plant facility in California after August 30, 2010. The Company has established an appropriate accrual pending potential regulatory action by San Diego Gas & Electric regarding the Company's Encina facility.

XML

Environmental Matters

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Environmental Matters

Environmental Matters

NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. The electric generation industry has been facing increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose additional restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. The Company has elected to use a $1 million disclosure threshold, as permitted, for environmental proceedings to which the government is a party.

Air

On July 8, 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. The ACE rule required states that have coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). On October 29, 2021, the U.S. Supreme Court agreed to review the D.C. Circuit's decision, which should provide some clarity regarding the scope of the EPA's authority to regulate CO2 under the Clean Air Act. The Company expects the EPA to promulgate a new rule to regulate GHG emissions from power plants after a decision from the U.S. Supreme Court.

Water

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines ("ELG") for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule. While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation. The EPA anticipates releasing a proposed rule in fall 2022. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants in Texas.

Byproducts, Wastes, Hazardous Materials and Contamination

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amended the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. In 2019 and 2020, the EPA proposed several changes to this rule. On August 28, 2020, the EPA finalized "A Holistic Approach to Close Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing impoundments with an alternative liner.

XML

Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Use of Estimates

Use of EstimatesThe preparation of financial statements in conformity with GAAP 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.

Reclassifications

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

Credit Losses

Credit Losses

Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues a provision 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.

Restricted Cash

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties related to NRG's hedging program. The increase in funds deposited by counterparties is driven by the significant increase in forward positions as a result of increases in natural gas and power prices. Though some amounts are segregated into separate accounts, not all funds are contractually restricted. Based on the Company's intention, these funds are not available for the payment of general corporate obligations; however, they are available for liquidity management. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the 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.

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

Winter Storm Uri Uplift Securitization Proceeds

Winter Storm Uri Uplift Securitization Proceeds

The Texas Legislature passed House Bill ("HB") 4492 in May of 2021 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.

In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement methodology. The Company accounted for the proceeds it will receive by analogy to the contribution model within ASC 958-605, Not-for-Profit Entities- Revenue Recognition and the grant model within IAS 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to cost of operations within its consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company expects to receive proceeds of $689 million from ERCOT in the second quarter of 2022 which is reflected as a receivable on its consolidated balance sheets.

Recent Accounting Developments

Recent Accounting Developments - Guidance Adopted in 2022

ASU 2020-06 — In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40), or ASU 2020-06. The guidance in ASU 2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock. In addition, ASU 2020-06 improves and amends the related earnings per share guidance. The Company adopted this standard on January 1, 2022 using the modified retrospective approach. As a result of the provisions of the amended guidance, the Company recorded a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings and a $14 million decrease to long-term deferred tax liabilities. The adoption of ASU 2020-06 did not have a material impact on the Company's statement of operations, statement of cash flow or earnings per share amounts.

Nuclear Decommissioning

NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its 44% interest in STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, 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 OCI, consistent with regulatory treatment.

Segment Reporting

The Company’s segment structure reflects how management currently makes financial decisions and allocates resources. The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus. NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and allocation of capital, as well as net income/(loss).

XML

Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Other Balance Sheet Information

The following table presents the accumulated depreciation included in property, plant and equipment, net and accumulated amortization included in intangible assets, net:

(In millions)	March 31, 2022		December 31, 2021
Property, plant and equipment accumulated depreciation	$	1,419	$	1,308
Intangible assets accumulated amortization	1,867		1,636

Activity in Allowance for Credit Losses

The following table represents the activity in the allowance for credit losses for the three months ended March 31, 2022 and 2021:

	Three months ended March 31,
(In millions)	2022		2021
Beginning balance	$	683	$	67
Acquired balance from Direct Energy	—		112
Provision for credit losses	25		611
Write-offs	(50)		(48)
Recoveries collected	8		7
Ending balance	$	666	$	749

Reconciliation of Cash and Cash Equivalents, Restricted Cash and Funds Deposited by Counterparties

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:

(In millions)	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	387	$	250
Funds deposited by counterparties	2,570		845
Restricted cash	39		15
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	2,996	$	1,110

XML

Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue from Contracts with Customer

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three months ended March 31, 2022 and 2021:

	Three months ended March 31, 2022
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,289	$	675	$	697	$	—	$	2,661
Business	663		3,846		400		—		4,909
Total retail revenue	1,952		4,521		1,097		—		7,570
Energy revenue(b)	15		204		54		5		278
Capacity revenue(b)	—		115		1		—		116
Mark-to-market for economic hedging activities(c)	(2)		(130)		(18)		17		(133)
Contract amortization	—		(9)		—		—		(9)
Other revenue(b)	58		17		4		(5)		74
Total revenue	2,023		4,718		1,138		17		7,896
Less: Revenues accounted for under topics other than 606 and 815	—		(9)		11		—		2
Less: Realized and unrealized ASC 815 revenue	(7)		(66)		(42)		20		(95)
Total revenue from contracts with customers	$	2,030	$	4,793	$	1,169	$	(3)	$	7,989
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	45	$	(20)	$	4	$	29
Capacity revenue	—		13		—		—		13
Other revenue	(5)		6		(4)		(1)		(4)
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

	Three months ended March 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,333	$	584	$	554	$	—	$	2,471
Business	781		2,629		281		—		3,691
Total retail revenue	2,114		3,213		835		—		6,162
Energy revenue(c)	285		126		70		1		482
Capacity revenue(c)	—		141		14		—		155
Mark-to-market for economic hedging activities(d)	(1)		(4)		(28)		1		(32)
Other revenue(b)(c)	1,304		19		4		(3)		1,324
Total revenue	3,702		3,495		895		(1)		8,091
Less: Revenues accounted for under topics other than 606 and 815	—		—		2		—		2
Less: Realized and unrealized ASC 815 revenue	93		99		(34)		2		160
Total revenue from contracts with customers	$	3,609	$	3,396	$	927	$	(3)	$	7,929
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.2 billion driven by high pricing during Winter Storm Uri
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	60	$	(4)	$	2	$	58
Capacity revenue	—		37		—		—		37
Other revenue	94		6		(2)		(1)		97
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

Contract Asset and Liabilities

The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of March 31, 2022 and December 31, 2021:

(In millions)	March 31, 2022		December 31, 2021
Deferred customer acquisition costs	$	111	$	133
Accounts receivable, net - Contracts with customers	3,091		3,057
Accounts receivable, net - Derivative instruments	197		182
Accounts receivable, net - Affiliate	3		6
Total accounts receivable, net	$	3,291	$	3,245
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,237	$	1,574
Deferred revenues(a)	177		227

(a) Deferred revenues from contracts with customers for the three months ended March 31, 2022 and the year ended December 31, 2021 were approximately $169 million and $224 million, respectively

XML

Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

Estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value

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

	March 31, 2022				December 31, 2021
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Convertible Senior Notes	$	575	$	633	$	518	$	677
Other long-term debt, including current portion	7,523		7,128		7,522		7,650
Total long-term debt, including current portion(a)	$	8,098	$	7,761	$	8,040	$	8,327

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

Assets and liabilities measured and recorded at fair value on the consolidated balance sheets on a recurring basis

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

	March 31, 2022
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	17	$	—	$	17	$	—
Nuclear trust fund investments:
Cash and cash equivalents	17		17		—		—
U.S. government and federal agency obligations	106		105		1		—
Federal agency mortgage-backed securities	104		—		104		—
Commercial mortgage-backed securities	41		—		41		—
Corporate debt securities	116		—		116		—
Equity securities	471		471		—		—
Foreign government fixed income securities	2		—		2		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	12,650		2,528		9,403		719
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	92
Equity securities (classified within other non-current assets)	7
Total assets	$	13,624	$	3,122	$	9,684	$	719
Derivative liabilities:
Foreign exchange contracts	$	4	$	—	$	4	$	—
Commodity contracts	8,049		1,173		6,685		191
Total liabilities	$	8,053	$	1,173	$	6,689	$	191

	December 31, 2021
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	32	$	15	$	17	$	—
Nuclear trust fund investments:
Cash and cash equivalents	33		33		—		—
U.S. government and federal agency obligations	112		111		1		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	44		—		44		—
Corporate debt securities	122		—		122		—
Equity securities	494		494		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Foreign exchange contracts	1		—		1		—
Commodity contracts	7,139		981		5,701		457
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	99
Equity securities (classified within other non-current assets)	7
Total assets	$	8,188	$	1,635	$	5,990	$	457
Derivative liabilities:
Foreign exchange contracts	$	1	$	—	$	1	$	—
Commodity contracts	4,798		626		4,008		164
Total liabilities	$	4,799	$	626	$	4,009	$	164

Reconciliation of 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

The following table reconciles, for the three months ended March 31, 2022 and 2021, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs:

	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Derivatives(a)
(In millions)	Three months ended March 31, 2022		Three months ended March 31, 2021
Beginning balance	$	293	$	(16)
Contracts added from Direct Energy acquisition	—		(15)
Total gains realized/unrealized — included in earnings	166		180
Purchases	23		20
Transfers into Level 3(b)	53		4
Transfers out of Level 3(b)	(7)		(14)
Ending balance	$	528	$	159
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 period end	$	237	$	146

(a)Consists of derivative 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 in/out are with Level 2

Significant unobservable inputs used developing fair values, Quantitative Information

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of March 31, 2022 and December 31, 2021:

	March 31, 2022
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	$	676	$	153	Discounted Cash Flow	Forward Market Price (per MWh)	$	6	$	278	$	47
FTRs	43		38		Discounted Cash Flow	Auction Prices (per MWh)	(105)		43		0
	$	719	$	191

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

Fair value inputs, sensitivity analysis

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of March 31, 2022 and December 31, 2021:

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

Net counterparty credit exposure by industry sector and by counterparty credit quality

The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.

	Net Exposure(a)(b)
Category by Industry Sector	(% of Total)
Utilities, energy merchants, marketers and other	59	%
Financial institutions	41
Total as of March 31, 2022	100	%

	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	59	%
Non-investment grade/non-rated	41
Total as of March 31, 2022	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

XML

Nuclear Decommissioning Trust Fund (Tables)

3 Months Ended

Mar. 31, 2022

Regulated Operations [Abstract]

Summary of aggregate fair values and unrealized gains and losses for the securities held in the trust fund

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

	As of March 31, 2022							As of December 31, 2021
(In millions, except maturities)	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	$	17	$	—	$	—	—	$	33	$	—	$	—	—
U.S. government and federal agency obligations	106		2		4		10	112		5		1		10
Federal agency mortgage-backed securities	104		1		3		25	100		2		—		25
Commercial mortgage-backed securities	41		—		2		27	44		1		—		27
Corporate debt securities	116		2		5		14	122		7		1		14
Equity securities	563		424		—		—	593		456		—		—
Foreign government fixed income securities	2		—		—		19	4		—		—		13
Total	$	949	$	429	$	14		$	1,008	$	471	$	2

Summary of proceeds from sales of available-for-sale securities and the related realized gains and losses

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

	Three months ended March 31,
(In millions)	2022		2021
Realized gains	$	1	$	3
Realized losses	(4)		(2)
Proceeds from sale of securities	161		118

XML

Accounting for Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of March 31, 2022 and December 31, 2021. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.

		Total Volume (In millions)
Category	Units	March 31, 2022		December 31, 2021
Emissions	Short Ton	—		1
Renewable Energy Certificates	Certificates	13		13
Coal	Short Ton	14		19
Natural Gas	MMBtu	811		813
Oil	Barrels	—		1
Power	MWh	175		185
Foreign Exchange	Dollars	$	264	$	279

Fair value within the derivative instrument valuation on the balance sheets

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

	Fair Value
	Derivative Assets				Derivative Liabilities
(In millions)	March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Foreign exchange contracts - current	$	—	$	—	$	2	$	1
Foreign exchange contracts - long-term	—		1		2		—
Commodity contracts - current	9,089		4,613		6,074		3,386
Commodity contracts - long-term	3,561		2,526		1,975		1,412
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	12,650	$	7,140	$	8,053	$	4,799

Offsetting of derivatives by counterparty assets

The following table summarizes the offsetting of 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 March 31, 2022
Foreign exchange contracts:
Derivative liabilities	$	(4)	$	—	$	—	$	(4)
Commodity contracts:
Derivative assets	$	12,650	$	(7,482)	$	(2,631)	$	2,537
Derivative liabilities	(8,049)		7,482		41		(526)
Total commodity contracts	$	4,601	$	—	$	(2,590)	$	2,011
Total derivative instruments	$	4,597	$	—	$	(2,590)	$	2,007

	Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
As of December 31, 2021
Foreign exchange contracts:
Derivative assets	$	1	$	(1)	$	—	$	—
Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	$	—	$	—	$	—	$	—
Commodity contracts:
Derivative assets	$	7,139	$	(4,440)	$	(831)	$	1,868
Derivative liabilities	(4,798)		4,440		17		(341)
Total commodity contracts	$	2,341	$	—	$	(814)	$	1,527
Total derivative instruments	$	2,341	$	—	$	(814)	$	1,527

Offsetting of derivatives by counterparty, liabilities

The following table summarizes the offsetting of 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 March 31, 2022
Foreign exchange contracts:
Derivative liabilities	$	(4)	$	—	$	—	$	(4)
Commodity contracts:
Derivative assets	$	12,650	$	(7,482)	$	(2,631)	$	2,537
Derivative liabilities	(8,049)		7,482		41		(526)
Total commodity contracts	$	4,601	$	—	$	(2,590)	$	2,011
Total derivative instruments	$	4,597	$	—	$	(2,590)	$	2,007

	Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
As of December 31, 2021
Foreign exchange contracts:
Derivative assets	$	1	$	(1)	$	—	$	—
Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	$	—	$	—	$	—	$	—
Commodity contracts:
Derivative assets	$	7,139	$	(4,440)	$	(831)	$	1,868
Derivative liabilities	(4,798)		4,440		17		(341)
Total commodity contracts	$	2,341	$	—	$	(814)	$	1,527
Total derivative instruments	$	2,341	$	—	$	(814)	$	1,527

Pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges and trading activity on the Company's statement of operations

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

(In millions)	Three months ended March 31,
Unrealized mark-to-market results	2022		2021
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(408)	$	17
Reversal of acquired (gain)/loss positions related to economic hedges	(60)		145
Net unrealized gains on open positions related to economic hedges	2,745		559
Total unrealized mark-to-market gains for economic hedging activities	2,277		721
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	1		(7)
Net unrealized (losses)/gains on open positions related to trading activity	(15)		11
Total unrealized mark-to-market (losses)/gains for trading activity	(14)		4
Total unrealized gains	$	2,263	$	725

	Three months ended March 31,
(In millions)	2022		2021
Unrealized (losses) included in revenues - commodities	$	(147)	$	(28)
Unrealized gains included in cost of operations - commodities	2,414		755
Unrealized (losses) included in cost of operations - foreign exchange	(4)		(2)
Total impact to statement of operations - commodities	$	2,263	$	725

XML

Long-term Debt and Finance Leases (Tables)

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Long-term Debt and Finance Leases

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

(In millions, except rates)	March 31, 2022		December 31, 2021		Interest rate %
Recourse debt:
Senior Notes, due 2027	$	375	$	375	6.625
Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	733		733		5.250
Senior Notes, due 2029	500		500		3.375
Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	1,100		1,100		3.875
Convertible Senior Notes, due 2048(a)	575		575		2.750
Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2025	500		500		2.000
Senior Secured First Lien Notes, due 2027	900		900		2.450
Senior Secured First Lien Notes, due 2029	500		500		4.450
Tax-exempt bonds	466		466		1.250 - 4.750
Subtotal recourse debt	8,100		8,100
Finance leases	13		13		various
Subtotal long-term debt and finance leases (including current maturities)	8,113		8,113
Less current maturities	(4)		(4)
Less debt issuance costs	(81)		(83)
Discounts	(2)		(60)
Total long-term debt and finance leases	$	8,026	$	7,966

(a)As of the ex-dividend date of April 29, 2022, the Convertible Senior Notes were convertible at a price of 44.15, which is equivalent to a conversion rate of approximately 22.6516 shares of common stock per $1,000 principal amount.

Schedule of Debt Instrument, Interest Expense

The following table details the interest expense recorded in connection with the Convertible Senior Notes, due 2048:

($ In millions)	For the three months ended March 31, 2022			For the three months ended March 31, 2021
Contractual interest expense	$	4		$	4
Amortization of discount and deferred finance costs	—			4
Total	$	4		$	8
Effective Interest Rate	0.76		%	1.32		%

XML

Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs (Tables)

3 Months Ended

Mar. 31, 2022

Variable Interest Entities Disclosure [Abstract]

Financial Information for Consolidated VIEs

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

(In millions)	March 31, 2022		December 31, 2021
Accounts receivable and Other current assets	$	573	$	939
Current liabilities	78		78
Net assets	$	495	$	861

XML

Changes in Capital Structure (Tables)

3 Months Ended

Mar. 31, 2022

Equity [Abstract]

Changes in NRG's common shares issued and outstanding

As of March 31, 2022 and December 31, 2021, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:

	Issued	Treasury	Outstanding
Balance as of December 31, 2021	423,547,174	(179,793,275)	243,753,899
Shares issued under LTIPs	292,630	—	292,630
Shares repurchased	—	(4,830,389)	(4,830,389)
Balance as of March 31, 2022	423,839,804	(184,623,664)	239,216,140
Shares issued under LTIPs	13,213	—	13,213
Shares issued under ESPP	—	68,941	68,941
Shares repurchased	—	(2,014,734)	(2,014,734)
Balance as of April 30, 2022	423,853,017	(186,569,457)	237,283,560

Shares Repurchased

The following repurchases have been made during the three months ended March 31, 2022 and through April 30, 2022:

	Total number of shares and share equivalents purchased	Average price paid per share and share equivalent	Amounts paid for shares and share equivalents purchased (in millions)
2022 repurchases
Repurchases(a)	4,830,389		$	187
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	131,899		6
Total Share Repurchases during the three months ended March 31, 2022	4,962,288	$38.78	193
Repurchases made during April 2022	2,014,734		$	76
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	5,465		—
Total Share Repurchases January 1, 2022 through April 30, 2022	6,982,487	$38.55	$	269

(a)Includes $10 million accrued as of March 31, 2022

(b)NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management. The average price per equivalent shares withheld was $43.03 and $39.19 for the three months ended March 31, 2022 and for April 2022, respectively

XML

Income/(loss) Per Share (Tables)

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Reconciliation of NRG's basic and diluted (loss)/income per share

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

	Three months ended March 31,
(In millions, except per share data)	2022		2021
Basic income/(loss) per share:
Net income/(loss)	$	1,736	$	(82)
Weighted average number of common shares outstanding - basic	242		245
Income/(loss) per weighted average common share — basic	$	7.17	$	(0.33)
Diluted income/(loss) per share:
Net income/(loss)	$	1,736	$	(82)
Weighted average number of common shares outstanding - basic	242		245
Weighted average number of common shares outstanding - dilutive	242		245
Income/(loss) per weighted average common share — diluted	$	7.17	$	(0.33)

XML

Segment Reporting (Tables)

3 Months Ended

Mar. 31, 2022

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended March 31, 2022
(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Revenue	$	2,023	$	4,718	$	1,138	$	—	$	17	$	7,896
Depreciation and amortization	76		78		21		8		—		183
Loss on sale of assets	—		—		(1)		(2)		—		(3)
Equity in (losses) of unconsolidated affiliates	(1)		—		(14)		—		—		(15)
Income/(loss) before income taxes	773		1,541		124		(131)		—		2,307
Net income/(loss)	$	773	$	1,541	$	125	$	(703)	$	—	$	1,736

	Three months ended March 31, 2021
(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Revenue	$	3,702	$	3,495	$	895	$	—	$	(1)	$	8,091
Depreciation and amortization	77		206		27		7		—		317
Gain on sale of assets	—		—		17		—		—		17
Equity in (losses) of unconsolidated affiliates	(1)		—		(5)		—		—		(6)
(Loss)/income before income taxes	(433)		356		79		(169)		—		(167)
Net (loss)/income	$	(433)	$	356	$	74	$	(79)	$	—	$	(82)

XML

Income Taxes (Tables)

3 Months Ended

Mar. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Provision

The income tax provision consisted of the following:

	Three months ended March 31,
(In millions, except rates)	2022			2021
Income before income taxes	$	2,307		$	(167)
Income tax expense/(benefit)	571			(85)
Effective income tax rate	24.8		%	50.9		%

XML

Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2022

Related Party Transactions [Abstract]

Summary of NRG's Material Related Party Transactions

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

	Three months ended March 31,
(In millions)	2022		2021
Revenues from Related Parties Included in Revenue
Gladstone	$	1	$	1
Ivanpah(a)	13		12
Midway-Sunset	2		2
Total	$	16	$	15

(a)Also includes fees under project management agreements with each project company

XML

Nature of Business and Basis of Presentation - General (Details) counterparty in Millions	3 Months Ended
	Mar. 31, 2022 counterparty MW	Jun. 30, 2021 MW
Business Acquisition [Line Items]
Generation capacity (in MW)	18,000
PJM Coal Generating Assets
Business Acquisition [Line Items]
Generation capacity (in MW)		1,600
Home
Business Acquisition [Line Items]
Customers | counterparty	6

XML

Summary of Significant Accounting Policies - Other Balance Sheet Information (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Property, plant and equipment accumulated depreciation	$ 1,419	$ 1,308
Intangible assets accumulated amortization	$ 1,867	$ 1,636

XML

Summary of Significant Accounting Policies - Activity in the Allowance for Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 683	$ 67
Acquired balance from Direct Energy	0	112
Provision for credit losses	25	611
Write-offs	(50)	(48)
Recoveries collected	8	7
Ending balance	666	$ 749
Decrease in provision for credit losses due finance hedge risk	393
Decrease in provision for credit losses due to counterparty credit risk	109
Decrease in provision for credit losses due to shortfall payments	$ 83

XML

Summary of Significant Accounting Policies - Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Cash and cash equivalents	$ 387	$ 250
Funds deposited by counterparties	2,570	845
Restricted cash	39	15
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$ 2,996	$ 1,110	$ 574	$ 3,930

XML

Summary of Significant Accounting Policies - Securitization Receivable (Details) - USD ($) $ in Millions	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
Subsequent Event [Line Items]
Uplift securitization proceeds receivable from ERCOT		$ 689	$ 689
Subsequent Event | Forecast
Subsequent Event [Line Items]
Uplift securitization proceeds receivable from ERCOT	$ 689

XML

Summary of Significant Accounting Policies - Adoption of New Accounting Policy (Details) - USD ($) $ in Millions	Mar. 31, 2022	Jan. 01, 2022	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2020
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of new accounting guidance	$ 5,030		$ 3,600	$ 1,517	$ 1,680
Additional Paid-In Capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of new accounting guidance	8,433		8,531	8,513	8,517
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of new accounting guidance	$ 2,171		464	$ (1,565)	$ (1,403)
Cumulative Effect, Period of Adoption, Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of new accounting guidance			(43)
Debt discount		$ 57
Deferred tax liabilities		14
Cumulative Effect, Period of Adoption, Adjustment | Additional Paid-In Capital
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of new accounting guidance		(100)	(100)
Cumulative Effect, Period of Adoption, Adjustment | Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Adjustment for adoption of new accounting guidance		$ 57	$ 57

XML

Revenue Recognition - Performance Obligations Expected Timing of Satisfaction (Details) $ in Millions	Mar. 31, 2022 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated future fixed fee performance obligations	$ 151
Revenue remaining performance obligation period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated future fixed fee performance obligations	$ 52
Revenue remaining performance obligation period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated future fixed fee performance obligations	$ 1
Revenue remaining performance obligation period	1 year

XML

Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 7,989	$ 7,929
Mark-to-market for economic hedging activities	2,277	721
Revenue	7,896	8,091
Less: Revenues accounted for under topics other than 606 and 815	2	2
Derivative revenue	2,263	725
Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(3)	(3)
Revenue	17	(1)
Less: Revenues accounted for under topics other than 606 and 815	0	0
Retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	7,570	6,162
Retail revenue | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Energy revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	278	482
Derivative revenue	29	58
Energy revenue | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	5	1
Derivative revenue	4	2
Capacity revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	116	155
Derivative revenue	13	37
Capacity revenue | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Derivative revenue	0	0
Derivative revenue
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	(133)	(32)
Less: Realized and unrealized ASC 815 revenue	(95)	160
Derivative revenue | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	17	1
Less: Realized and unrealized ASC 815 revenue	20	2
Other revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	74	1,324
Contract amortization	(9)
Other revenue | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(5)	(3)
Contract amortization	0
Total operating revenue
Disaggregation of Revenue [Line Items]
Revenue	7,896	8,091
Total operating revenue | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue	17	(1)
Other revenue, derivative
Disaggregation of Revenue [Line Items]
Derivative revenue	(4)	97
Other revenue, derivative | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Derivative revenue	(1)	(1)
Home | Retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,661	2,471
Home | Retail revenue | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business | Retail revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	4,909	3,691
Business | Retail revenue | Corporate/Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,030	3,609
Revenue	2,023	3,702
Less: Revenues accounted for under topics other than 606 and 815	0	0
Texas | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,952	2,114
Texas | Energy revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	15	285
Derivative revenue	0	0
Texas | Capacity revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Derivative revenue	0	0
Texas | Derivative revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	(2)	(1)
Less: Realized and unrealized ASC 815 revenue	(7)	93
Texas | Other revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	58	1,304
Contract amortization	0
Texas | Total operating revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue	2,023	3,702
Texas | Other revenue, derivative | Operating Segments
Disaggregation of Revenue [Line Items]
Derivative revenue	(5)	94
Texas | Other Ancillary | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		1,200
Texas | Home | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,289	1,333
Texas | Business | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	663	781
East | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	4,793	3,396
Revenue	4,718	3,495
Less: Revenues accounted for under topics other than 606 and 815	(9)	0
East | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	4,521	3,213
East | Energy revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	204	126
Derivative revenue	45	60
East | Capacity revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	115	141
Derivative revenue	13	37
East | Derivative revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	(130)	(4)
Less: Realized and unrealized ASC 815 revenue	(66)	99
East | Other revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	17	19
Contract amortization	(9)
East | Total operating revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue	4,718	3,495
East | Other revenue, derivative | Operating Segments
Disaggregation of Revenue [Line Items]
Derivative revenue	6	6
East | Home | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	675	584
East | Business | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	3,846	2,629
West/Services/Other | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,169	927
Revenue	1,138	895
Less: Revenues accounted for under topics other than 606 and 815	11	2
West/Services/Other | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,097	835
West/Services/Other | Energy revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	54	70
Derivative revenue	(20)	(4)
West/Services/Other | Capacity revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1	14
Derivative revenue	0	0
West/Services/Other | Derivative revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Mark-to-market for economic hedging activities	(18)	(28)
Less: Realized and unrealized ASC 815 revenue	(42)	(34)
West/Services/Other | Other revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	4	4
Contract amortization	0
West/Services/Other | Total operating revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue	1,138	895
West/Services/Other | Other revenue, derivative | Operating Segments
Disaggregation of Revenue [Line Items]
Derivative revenue	(4)	(2)
West/Services/Other | Home | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	697	554
West/Services/Other | Business | Retail revenue | Operating Segments
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 400	$ 281

XML

Revenue Recognition - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Schedule Of Contract Assets And Liabilities [Line Items]
Deferred customer acquisition costs	$ 111		$ 133
Total accounts receivable, net	3,291		3,245
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	1,237		1,574
Deferred revenues	177		227
Deferred revenue from contract with customers	169		224
Revenue recognized	117	$ 23
Accounts receivable, net - Contracts with customers
Schedule Of Contract Assets And Liabilities [Line Items]
Total accounts receivable, net	3,091		3,057
Accounts receivable, net - Derivative instruments
Schedule Of Contract Assets And Liabilities [Line Items]
Total accounts receivable, net	197		182
Accounts receivable, net - Affiliate
Schedule Of Contract Assets And Liabilities [Line Items]
Total accounts receivable, net	$ 3		$ 6

XML

Acquisitions and Dispositions - Acquisitions Narrative (Details) $ in Millions	Jan. 05, 2021 USD ($) customer province state
Canada
Business Acquisition [Line Items]
Provinces in which entity operates | province	8
Direct Energy
Business Acquisition [Line Items]
Customers added (over) | customer	3,000,000
Purchase price	$ 3,625
Purchase price adjustment	99
Adjusted purchase price	$ 3,724
Direct Energy | U.S.
Business Acquisition [Line Items]
States in which entity operates | state	50

XML

Acquisitions and Dispositions - Dispositions (Details) - USD ($) $ in Millions		3 Months Ended
	Feb. 03, 2021	Mar. 31, 2022	Mar. 31, 2021
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale		$ (3)	$ 17
Agua Caliente Solar Project | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of ownership sold	35.00%
Cash consideration	$ 202
Gain on sale	17
Cash disposed	$ 7

XML

Fair Value of Financial Instruments - Estimated Carrying Amounts and Fair Value of Financial Instruments Not Carried at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Total long-term debt, including current portion	$ 8,098	$ 8,040
Carrying Amount | Convertible Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Total long-term debt, including current portion	575	518
Carrying Amount | Other long-term debt, including current portion
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Total long-term debt, including current portion	7,523	7,522
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Total long-term debt, including current portion	7,761	8,327
Fair Value | Convertible Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Total long-term debt, including current portion	633	677
Fair Value | Other long-term debt, including current portion
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Total long-term debt, including current portion	$ 7,128	$ 7,650

XML

Fair Value of Financial Instruments - Assets and Liabilities Measured and Recorded at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	$ 17	$ 32
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1	1
Measured using net asset value practical expedient:
Total assets	13,624	8,188
Derivative liabilities:
Commodity contracts	8,053	4,799
Foreign exchange contract
Derivative assets:
Derivative contracts		1
Derivative liabilities:
Commodity contracts	4	1
Commodity contracts
Derivative assets:
Derivative contracts	12,650	7,139
Derivative liabilities:
Commodity contracts	8,049	4,798
Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	17	33
U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	106	112
Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	104	100
Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	41	44
Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	116	122
Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	471	494
Measured using net asset value practical expedient:
Equity securities	7	7
Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	2	4
Equity securities — nuclear trust fund investments
Measured using net asset value practical expedient:
Equity securities	92	99
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	0	15
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	1	1
Measured using net asset value practical expedient:
Total assets	3,122	1,635
Derivative liabilities:
Commodity contracts	1,173	626
Level 1 | Foreign exchange contract
Derivative assets:
Derivative contracts		0
Derivative liabilities:
Commodity contracts	0	0
Level 1 | Commodity contracts
Derivative assets:
Derivative contracts	2,528	981
Derivative liabilities:
Commodity contracts	1,173	626
Level 1 | Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	17	33
Level 1 | U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	105	111
Level 1 | Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 1 | Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 1 | Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 1 | Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	471	494
Level 1 | Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	17	17
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	0	0
Measured using net asset value practical expedient:
Total assets	9,684	5,990
Derivative liabilities:
Commodity contracts	6,689	4,009
Level 2 | Foreign exchange contract
Derivative assets:
Derivative contracts		1
Derivative liabilities:
Commodity contracts	4	1
Level 2 | Commodity contracts
Derivative assets:
Derivative contracts	9,403	5,701
Derivative liabilities:
Commodity contracts	6,685	4,008
Level 2 | Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 2 | U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	1	1
Level 2 | Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	104	100
Level 2 | Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	41	44
Level 2 | Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	116	122
Level 2 | Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 2 | Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	2	4
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments in securities (classified within other current and non-current assets)	0	0
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	0	0
Measured using net asset value practical expedient:
Total assets	719	457
Derivative liabilities:
Commodity contracts	191	164
Level 3 | Foreign exchange contract
Derivative assets:
Derivative contracts		0
Derivative liabilities:
Commodity contracts	0	0
Level 3 | Commodity contracts
Derivative assets:
Derivative contracts	719	457
Derivative liabilities:
Commodity contracts	191	164
Level 3 | Cash and cash equivalents
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | U.S. government and federal agency obligations
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Federal agency mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Commercial mortgage-backed securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Corporate debt securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Equity securities
Nuclear trust fund investments:
Nuclear trust fund investments	0	0
Level 3 | Foreign government fixed income securities
Nuclear trust fund investments:
Nuclear trust fund investments	$ 0	$ 0

XML

Fair Value of Financial Instruments - Reconciliation of Level 3 Financial Instruments (Details) - Level 3 - Derivatives - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 293	$ (16)
Contracts added from Direct Energy acquisition	0	(15)
Total gains realized/unrealized — included in earnings	166	180
Purchases	23	20
Transfers into Level 3	53	4
Transfers out of Level 3	(7)	(14)
Ending balance	528	159
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 period end	$ 237	$ 146

XML

Fair Value of Financial Instruments - Derivative Fair Value Measurements, Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Total derivative assets valued with prices provided by models and other valuation techniques (as a percent)	6.00%
Total derivative liabilities valued with prices provided by models and other valuation techniques (as a percent)	2.00%
Change in credit reserve	$ 5	$ 11

XML

Fair Value of Financial Instruments - Derivative Fair Value Measurements (Details) $ in Millions	Mar. 31, 2022 USD ($) $ / MWh	Dec. 31, 2021 USD ($) $ / MWh
Liabilities
Commodity contracts	$ 8,053	$ 4,799
Level 3
Liabilities
Commodity contracts	191	164
Commodity contracts
Assets
Derivative assets	12,650	7,139
Liabilities
Commodity contracts	8,049	4,798
Commodity contracts | Level 3
Assets
Derivative assets	719	457
Liabilities
Commodity contracts	191	164
Commodity contracts | Level 3 | Natural Gas Contracts
Assets
Derivative assets		16
Liabilities
Commodity contracts		$ 1
Commodity contracts | Level 3 | Natural Gas Contracts | Low
Fair Value Inputs / Range
Forward Market Price (per MWh) | $ / MWh		3
Commodity contracts | Level 3 | Natural Gas Contracts | High
Fair Value Inputs / Range
Forward Market Price (per MWh) | $ / MWh		40
Commodity contracts | Level 3 | Natural Gas Contracts | Weighted Average
Fair Value Inputs / Range
Forward Market Price (per MWh) | $ / MWh		15
Commodity contracts | Level 3 | Power Contracts
Assets
Derivative assets	676	$ 392
Liabilities
Commodity contracts	$ 153	$ 121
Commodity contracts | Level 3 | Power Contracts | Low
Fair Value Inputs / Range
Forward Market Price (per MWh) | $ / MWh	6	3
Commodity contracts | Level 3 | Power Contracts | High
Fair Value Inputs / Range
Forward Market Price (per MWh) | $ / MWh	278	212
Commodity contracts | Level 3 | Power Contracts | Weighted Average
Fair Value Inputs / Range
Forward Market Price (per MWh) | $ / MWh	47	35
Commodity contracts | Level 3 | FTRs
Assets
Derivative assets	$ 43	$ 49
Liabilities
Commodity contracts	$ 38	$ 42
Commodity contracts | Level 3 | FTRs | Low
Fair Value Inputs / Range
Auction Prices (per MWh) | $ / MWh	(105)	(122)
Commodity contracts | Level 3 | FTRs | High
Fair Value Inputs / Range
Auction Prices (per MWh) | $ / MWh	43	43
Commodity contracts | Level 3 | FTRs | Weighted Average
Fair Value Inputs / Range
Auction Prices (per MWh) | $ / MWh	0	0

XML

Fair Value of Financial Instruments - Counterparty Credit Risk (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Concentration of Credit Risk
Counterparty credit exposure to a portion of the Company's counterparties	$ 3,200
Collateral held (cash and letters of credit) against counterparty credit exposure to a portion of the Company's counterparties	1,500
Net counterparty credit exposure to a portion of the Company's counterparties	$ 1,800
Company's exposure before collateral expected to roll off (as a percent)	82.00%
Net exposure (as a percent)	100.00%
Counterparty credit risk exposure to certain counterparties, threshold (as a percent)	10.00%
Estimated counterparty credit risk exposure under certain long term agreements for the next 5 years	$ 1,200
Period of estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements (in years)	5 years
Designated as Hedging Instrument
Concentration of Credit Risk
Counterparty credit exposure to a portion of the Company's counterparties		$ 393
Investment grade
Concentration of Credit Risk
Net exposure (as a percent)	59.00%
Non-Investment grade/Non-Rated
Concentration of Credit Risk
Net exposure (as a percent)	41.00%
Utilities, energy merchants, marketers and other
Concentration of Credit Risk
Net exposure (as a percent)	59.00%
Financial Institutions
Concentration of Credit Risk
Net exposure (as a percent)	41.00%

XML

Nuclear Decommissioning Trust Fund - Narrative (Details)	Mar. 31, 2022
STP
Nuclear decommissioning trust fund
Ownership interest as percentage	44.00%

XML

Nuclear Decommissioning Trust Fund - Summary of aggregate fair values and realized gains and losses (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Nuclear decommissioning trust fund
Fair Value	$ 949	$ 1,008
Unrealized Gains	429	471
Unrealized Losses	14	2
Cash and cash equivalents
Nuclear decommissioning trust fund
Fair Value	17	33
Unrealized Gains	0	0
Unrealized Losses	0	0
U.S. government and federal agency obligations
Nuclear decommissioning trust fund
Fair Value	106	112
Unrealized Gains	2	5
Unrealized Losses	$ 4	$ 1
Weighted-average Maturities (In years)	10 years	10 years
Federal agency mortgage-backed securities
Nuclear decommissioning trust fund
Fair Value	$ 104	$ 100
Unrealized Gains	1	2
Unrealized Losses	$ 3	$ 0
Weighted-average Maturities (In years)	25 years	25 years
Commercial mortgage-backed securities
Nuclear decommissioning trust fund
Fair Value	$ 41	$ 44
Unrealized Gains	0	1
Unrealized Losses	$ 2	$ 0
Weighted-average Maturities (In years)	27 years	27 years
Corporate debt securities
Nuclear decommissioning trust fund
Fair Value	$ 116	$ 122
Unrealized Gains	2	7
Unrealized Losses	$ 5	$ 1
Weighted-average Maturities (In years)	14 years	14 years
Equity securities
Nuclear decommissioning trust fund
Fair Value	$ 563	$ 593
Unrealized Gains	424	456
Unrealized Losses	0	0
Foreign government fixed income securities
Nuclear decommissioning trust fund
Fair Value	2	4
Unrealized Gains	0	0
Unrealized Losses	$ 0	$ 0
Weighted-average Maturities (In years)	19 years	13 years

XML

Nuclear Decommissioning Trust Fund - Summary of proceeds from sales of available-for-sale securities and related gains and losses (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Regulated Operations [Abstract]
Realized gains	$ 1	$ 3
Realized losses	(4)	(2)
Proceeds from sale of securities	$ 161	$ 118

XML

Accounting for Derivative Instruments and Hedging Activities - Net notional volume buy/sell of open derivative transactions (Details) certificate in Millions, bbl in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022 USD ($) MMBTU MWh certificate T bbl	Dec. 31, 2021 USD ($) MMBTU MWh certificate T bbl
Long | Emissions
Volumetric Underlying Derivative Transactions
Derivative, nonmonetary notional amount, mass (ton)	0	1
Long | Renewable Energy Certificates
Volumetric Underlying Derivative Transactions
Derivative, non-monetary notional amount (in shares) | certificate	13	13
Long | Coal
Volumetric Underlying Derivative Transactions
Derivative, nonmonetary notional amount, mass (ton)	14	19
Long | Oil
Volumetric Underlying Derivative Transactions
Derivative, nonmonetary notional amount (in barrels) | bbl	0	1
Long | Power
Volumetric Underlying Derivative Transactions
Derivative, nonmonetary notional amount, energy measure (MMBtu/MW/Day) | MWh	175	185
Long | Foreign Exchange
Volumetric Underlying Derivative Transactions
Derivative, notional amount | $	$ 264	$ 279
Short | Natural Gas
Volumetric Underlying Derivative Transactions
Derivative, nonmonetary notional amount, energy measure (MMBtu/MW/Day) | MMBTU	811	813

XML

Accounting for Derivative Instruments and Hedging Activities - Fair value within the derivative instrument valuation (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Derivative Liabilities	$ 8,053	$ 4,799
Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative Assets	12,650	7,140
Derivative Liabilities	8,053	4,799
Not Designated as Hedging Instrument | Foreign exchange contracts - current
Derivative [Line Items]
Derivative Assets	0	0
Derivative Liabilities	2	1
Not Designated as Hedging Instrument | Foreign exchange contracts - long-term
Derivative [Line Items]
Derivative Assets	0	1
Derivative Liabilities	2	0
Not Designated as Hedging Instrument | Commodity contracts - current
Derivative [Line Items]
Derivative Assets	9,089	4,613
Derivative Liabilities	6,074	3,386
Not Designated as Hedging Instrument | Commodity contracts - long-term
Derivative [Line Items]
Derivative Assets	3,561	2,526
Derivative Liabilities	$ 1,975	$ 1,412

XML

Accounting for Derivative Instruments and Hedging Activities - Offsetting of derivatives by counterparty master agreement level and collateral received (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Cash collateral received in support of energy risk management activities	$ (2,570)	$ (845)
Derivative liabilities	(8,053)	(4,799)
Cash Collateral Posted	9	291
Total Derivative Contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Gross Amounts of Recognized Assets / Liabilities	4,597	2,341
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	(2,590)	(814)
Net Amount	2,007	1,527
Foreign exchange contract
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets		1
Derivative Instruments		(1)
Cash collateral received in support of energy risk management activities		0
Net Amount		0
Derivative liabilities	(4)	(1)
Derivative Instruments	0	1
Cash Collateral Posted	0	0
Net Amount	(4)	0
Gross Amounts of Recognized Assets / Liabilities		0
Derivative Instruments		0
Cash Collateral (Held) / Posted		0
Net Amount		0
Commodity contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	12,650	7,139
Derivative Instruments	(7,482)	(4,440)
Cash collateral received in support of energy risk management activities	(2,631)	(831)
Net Amount	2,537	1,868
Derivative liabilities	(8,049)	(4,798)
Derivative Instruments	7,482	4,440
Cash Collateral Posted	41	17
Net Amount	(526)	(341)
Gross Amounts of Recognized Assets / Liabilities	4,601	2,341
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	(2,590)	(814)
Net Amount	$ 2,011	$ 1,527

XML

Accounting for Derivative Instruments and Hedging Activities - Pre-tax effects of economic hedges not designated a cash flow hedges (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Unrealized mark-to-market results
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$ (408)	$ 17
Reversal of acquired (gain)/loss positions related to economic hedges	(60)	145
Net unrealized gains on open positions related to economic hedges	2,745	559
Total unrealized mark-to-market gains for economic hedging activities	2,277	721
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	1	(7)
Net unrealized (losses)/gains on open positions related to trading activity	(15)	11
Total unrealized mark-to-market (losses)/gains for trading activity	(14)	4
Total unrealized gains	2,263	725
Credit Risk Related Contingent Features
Unrealized gains from open economic hedge positions	2,700	559
Collateral due on net liability position that has not been called by a certain marginable agreement counterparty	56
Additional collateral required	26
Adequate Assurance Clauses
Credit Risk Related Contingent Features
Derivative net liability position, collateral required for contracts with credit rating contingent feature	790
Commodity contracts
Unrealized mark-to-market results
Total unrealized gains	2,263	725
Commodity contracts | Operating revenues
Unrealized mark-to-market results
Total unrealized gains	(147)	(28)
Commodity contracts | Cost of operations
Unrealized mark-to-market results
Total unrealized gains	2,414	755
Foreign exchange contract | Cost of operations
Unrealized mark-to-market results
Total unrealized gains	$ (4)	$ (2)

XML

Long-term Debt and Finance Leases - Schedule of Long-term Debt and Finance Leases (Details) $ / shares in Units, $ in Millions		3 Months Ended
	Apr. 29, 2022 $ / shares	Mar. 31, 2022 USD ($) $ / shares	Dec. 31, 2021 USD ($)
Debt Instrument [Line Items]
Finance leases		$ 13	$ 13
Subtotal long-term debt and finance leases (including current maturities)		8,113	8,113
Less current maturities		(4)	(4)
Less debt issuance costs		(81)	(83)
Discounts		(2)	(60)
Total long-term debt and finance leases		8,026	7,966
Recourse Debt
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		8,100	8,100
Recourse Debt | Senior Notes, due 2027
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 375	375
Interest rate, stated percentage		6.625%
Recourse Debt | Senior Notes, due 2028
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 821	821
Interest rate, stated percentage		5.75%
Recourse Debt | Senior Notes, due 2029
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 733	733
Interest rate, stated percentage		5.25%
Recourse Debt | Senior Notes, due 2029
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 500	500
Interest rate, stated percentage		3.375%
Recourse Debt | Senior Notes, due 2031
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 1,030	1,030
Interest rate, stated percentage		3.625%
Recourse Debt | Senior Notes, due 2032
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 1,100	1,100
Interest rate, stated percentage		3.875%
Recourse Debt | Convertible Senior Notes Due 2048
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 575	575
Interest rate, stated percentage		2.75%
Convertible notes, conversion price (in usd per share) | $ / shares		$ 44.53
Conversion rate		0.0224563
Recourse Debt | Convertible Senior Notes Due 2048 | Subsequent Event
Debt Instrument [Line Items]
Convertible notes, conversion price (in usd per share) | $ / shares	$ 44.15
Conversion rate	0.0226516
Recourse Debt | Senior Secured First Lien Notes, due 2024
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 600	600
Interest rate, stated percentage		3.75%
Recourse Debt | Senior Secured First Lien Notes, due 2025
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 500	500
Interest rate, stated percentage		2.00%
Recourse Debt | Senior Secured First Lien Notes, due 2027
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 900	900
Interest rate, stated percentage		2.45%
Recourse Debt | Senior Secured First Lien Notes, due 2029
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 500	500
Interest rate, stated percentage		4.45%
Recourse Debt | Tax-exempt bonds
Debt Instrument [Line Items]
Subtotal long-term debt (including current maturities)		$ 466	$ 466
Recourse Debt | Tax-exempt bonds | Minimum
Debt Instrument [Line Items]
Interest rate, stated percentage		1.25%
Recourse Debt | Tax-exempt bonds | Maximum
Debt Instrument [Line Items]
Interest rate, stated percentage		4.75%

XML

Long-term Debt and Finance Leases - Senior Notes (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2022	Jan. 01, 2022	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Discount amortization period	7 years
Adjustment for adoption of new accounting guidance	$ 5,030		$ 3,600	$ 1,517	$ 1,680
Additional Paid-In Capital
Debt Instrument [Line Items]
Adjustment for adoption of new accounting guidance	8,433		8,531	8,513	8,517
Retained Earnings
Debt Instrument [Line Items]
Adjustment for adoption of new accounting guidance	$ 2,171		464	$ (1,565)	$ (1,403)
Cumulative Effect, Period of Adoption, Adjustment
Debt Instrument [Line Items]
Adjustment for adoption of new accounting guidance			(43)
Debt discount		$ 57
Deferred tax liabilities		14
Cumulative Effect, Period of Adoption, Adjustment | Additional Paid-In Capital
Debt Instrument [Line Items]
Adjustment for adoption of new accounting guidance		(100)	(100)
Cumulative Effect, Period of Adoption, Adjustment | Retained Earnings
Debt Instrument [Line Items]
Adjustment for adoption of new accounting guidance		$ 57	$ 57
Recourse Debt | Convertible Senior Notes Due 2048
Debt Instrument [Line Items]
Convertible notes, conversion price (in usd per share)	$ 44.53

XML

Long-term Debt and Finance Leases - Interest Expense in Connection with Convertible Senior Notes, due 2048 (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Debt Instrument [Line Items]
Amortization of financing costs and debt discounts	$ 6	$ 11
Convertible Senior Notes Due 2048 | Recourse Debt
Debt Instrument [Line Items]
Contractual interest expense	4	4
Amortization of financing costs and debt discounts	0	4
Total	$ 4	$ 8
Effective Interest Rate	0.76%	1.32%

XML

Long-term Debt and Finance Leases - Repurchase Facility (Details) - Repurchase Facility - Secured Debt - USD ($)			3 Months Ended
	Apr. 29, 2022	Feb. 09, 2022	Mar. 31, 2022	Dec. 31, 2021
Line of Credit Facility [Line Items]
Credit facility borrowing available		$ 150,000,000		$ 75,000,000
Commitment fee			$ 0
Outstanding under Facility			$ 0
Subsequent Event
Line of Credit Facility [Line Items]
Increase to existing revolving facility	$ 100,000,000
Letter of Credit | Subsequent Event
Line of Credit Facility [Line Items]
Credit facility borrowing available	$ 575,000,000
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.30%

XML

Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Investments Accounted for by the Equity Method
Accounts receivable and Other current assets	$ 16,837	$ 10,841
Current liabilities	12,233	7,915
Variable Interest Entity, Primary Beneficiary
Investments Accounted for by the Equity Method
Accounts receivable and Other current assets	573	939
Current liabilities	78	78
Net assets	$ 495	$ 861

XML

Changes in Capital Structure - Changes in NRG's common stock issued and outstanding (Details) - shares	1 Months Ended	3 Months Ended
	Apr. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Common stock, shares authorized (in shares)		500,000,000	500,000,000
Schedule of Stock by Class, Equity [Roll Forward]
Balance as of beginning of period (in shares)	423,839,804	423,547,174
Treasury shares, balance as of beginning of period (in shares)	(184,623,664)	(179,793,275)
Outstanding, as of beginning of period (in shares)	239,216,140	243,753,899
Shares repurchased (in shares)		(4,830,389)
Balance as of end of period (in shares)		423,839,804
Treasury shares, balance as of end of the period (in shares)		(184,623,664)
Outstanding, as of end of period (in shares)		239,216,140
Shares issued under LTIPs
Schedule of Stock by Class, Equity [Roll Forward]
Shares issued under LTIPs (in shares)		292,630
Subsequent Event
Schedule of Stock by Class, Equity [Roll Forward]
Shares repurchased (in shares)	(2,014,734)
Outstanding, as of end of period (in shares)	237,283,560
Subsequent Event | Shares issued under LTIPs
Schedule of Stock by Class, Equity [Roll Forward]
Shares issued under LTIPs (in shares)	13,213
Subsequent Event | Shares issued under ESPP
Schedule of Stock by Class, Equity [Roll Forward]
Stock issued under ESPP (in shares)	68,941
Common Stock
Schedule of Stock by Class, Equity [Roll Forward]
Balance as of beginning of period (in shares)	423,839,804	423,547,174
Shares repurchased (in shares)		0
Balance as of end of period (in shares)		423,839,804
Common Stock | Shares issued under LTIPs
Schedule of Stock by Class, Equity [Roll Forward]
Shares issued under LTIPs (in shares)		292,630
Common Stock | Subsequent Event
Schedule of Stock by Class, Equity [Roll Forward]
Shares repurchased (in shares)	0
Balance as of end of period (in shares)	423,853,017
Common Stock | Subsequent Event | Shares issued under LTIPs
Schedule of Stock by Class, Equity [Roll Forward]
Shares issued under LTIPs (in shares)	13,213
Common Stock | Subsequent Event | Shares issued under ESPP
Schedule of Stock by Class, Equity [Roll Forward]
Stock issued under ESPP (in shares)	0
Treasury
Schedule of Stock by Class, Equity [Roll Forward]
Treasury shares, balance as of beginning of period (in shares)	(184,623,664)	(179,793,275)
Shares repurchased (in shares)		(4,830,389)
Treasury shares, balance as of end of the period (in shares)		(184,623,664)
Treasury | Shares issued under LTIPs
Schedule of Stock by Class, Equity [Roll Forward]
Shares issued under LTIPs (in shares)		0
Treasury | Subsequent Event
Schedule of Stock by Class, Equity [Roll Forward]
Shares repurchased (in shares)	(2,014,734)
Treasury shares, balance as of end of the period (in shares)	(186,569,457)
Treasury | Subsequent Event | Shares issued under LTIPs
Schedule of Stock by Class, Equity [Roll Forward]
Shares issued under LTIPs (in shares)	0
Treasury | Subsequent Event | Shares issued under ESPP
Schedule of Stock by Class, Equity [Roll Forward]
Stock issued under ESPP (in shares)	68,941

XML

Changes in Capital Structure - Narrative (Details) - USD ($)	1 Months Ended	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2022	Dec. 31, 2019	Dec. 31, 2021	Dec. 06, 2021
Class of Stock [Line Items]
Long-term capital allocation, target allocation, cash generated allocated to growth investments, percentage			50.00%
Long-term capital allocation, target allocation, cash generated allocated returned to shareholders, percentage			50.00%
ESPP, minimum percentage of eligible compensation to purchase shares	1.00%
ESPP, maximum percentage of eligible compensation	10.00%
ESPP, exercise price as percentage of fair value	95.00%
Capital Allocation Plan
Class of Stock [Line Items]
Stock repurchase program, authorized amount					$ 1,000,000,000
Amounts paid for shares purchased		$ 193,000,000		$ 44,000,000
Average price paid per share (in usd per share)		$ 38.78
Capital Allocation Plan, Open Market Repurchases
Class of Stock [Line Items]
Amounts paid for shares purchased		$ 187,000,000
Average price paid per share (in usd per share)		$ 38.66

XML

Changes in Capital Structure - Schedule of Repurchases Under Share Repurchase Programs (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Apr. 30, 2022	Mar. 31, 2022	Dec. 31, 2021
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)		4,830,389
Accrued stock repurchases		$ 10
Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	2,014,734
Capital Allocation Plan, Open Market Repurchases
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)		4,830,389
Average price paid per share (in usd per share)		$ 38.66
Amounts paid for shares and share equivalents purchased		$ 187
Capital Allocation Plan, Open Market Repurchases | Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	2,014,734
Amounts paid for shares and share equivalents purchased	$ 76
Equivalent Shares in Lieu of Tax Withholding on Equity Compensation Issuances
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)		131,899
Average price paid per share (in usd per share)		$ 43.03
Amounts paid for shares and share equivalents purchased		$ 6
Equivalent Shares in Lieu of Tax Withholding on Equity Compensation Issuances | Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	5,465
Average price paid per share (in usd per share)	$ 39.19
Amounts paid for shares and share equivalents purchased	$ 0
Capital Allocation Plan
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)		4,962,288
Average price paid per share (in usd per share)		$ 38.78
Amounts paid for shares and share equivalents purchased		$ 193	$ 44
Capital Allocation Plan | Subsequent Event
Schedule of Capitalization, Equity [Line Items]
Total number of shares purchased (in shares)	6,982,487
Average price paid per share (in usd per share)	$ 38.55
Amounts paid for shares and share equivalents purchased	$ 269

XML

Changes in Capital Structure - NRG Common Stock Dividends (Details) - $ / shares		3 Months Ended			12 Months Ended
	Apr. 20, 2022	Mar. 31, 2022	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2021
Subsequent Event [Line Items]
Common stock dividends proposed annual amount (in usd per share)		$ 1.40			$ 1.30
Dividends per common share (in usd per share)		$ 0.35	$ 0.35	$ 0.325
Subsequent Event
Subsequent Event [Line Items]
Common stock dividends declared (in usd per share)	$ 0.35
Minimum
Subsequent Event [Line Items]
Common stock, annual dividend growth rate, percentage		7.00%
Maximum
Subsequent Event [Line Items]
Common stock, annual dividend growth rate, percentage		9.00%

XML

Income/(loss) Per Share - Reconciliation of Basic and Diluted EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Basic income/(loss) per share:
Net income/(loss)	$ 1,736	$ (82)
Weighted average number of common shares outstanding — basic (in shares)	242,000	245,000
Income per weighted average common share — basic (in usd per share)	$ 7.17	$ (0.33)
Diluted income/(loss) per share:
Net income/(loss)	$ 1,736	$ (82)
Weighted average number of common shares outstanding — basic (in shares)	242,000	245,000
Weighted average number of common shares outstanding- dilutive (in shares)	242,000	245,000
Income per weighted average common share — diluted (in usd per share)	$ 7.17	$ (0.33)
Antidilutive securities (in shares)	1,000	1,000

XML

Segment Reporting (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Segment Reporting Information
Revenue	$ 7,896	$ 8,091
Depreciation and amortization	183	317
Gain (loss) on sale of assets	(3)	17
Equity in (losses) of unconsolidated affiliates	(15)	(6)
Income/(loss) before income taxes	2,307	(167)
Net income/(loss)	1,736	(82)
Corporate
Segment Reporting Information
Revenue	0	0
Depreciation and amortization	8	7
Gain (loss) on sale of assets	(2)	0
Equity in (losses) of unconsolidated affiliates	0	0
Income/(loss) before income taxes	(131)	(169)
Net income/(loss)	(703)	(79)
Eliminations
Segment Reporting Information
Revenue	17	(1)
Depreciation and amortization	0	0
Gain (loss) on sale of assets	0	0
Equity in (losses) of unconsolidated affiliates	0	0
Income/(loss) before income taxes	0	0
Net income/(loss)	0	0
Texas | Operating Segments
Segment Reporting Information
Revenue	2,023	3,702
Depreciation and amortization	76	77
Gain (loss) on sale of assets	0	0
Equity in (losses) of unconsolidated affiliates	(1)	(1)
Income/(loss) before income taxes	773	(433)
Net income/(loss)	773	(433)
East | Operating Segments
Segment Reporting Information
Revenue	4,718	3,495
Depreciation and amortization	78	206
Gain (loss) on sale of assets	0	0
Equity in (losses) of unconsolidated affiliates	0	0
Income/(loss) before income taxes	1,541	356
Net income/(loss)	1,541	356
West/Services/Other | Operating Segments
Segment Reporting Information
Revenue	1,138	895
Depreciation and amortization	21	27
Gain (loss) on sale of assets	(1)	17
Equity in (losses) of unconsolidated affiliates	(14)	(5)
Income/(loss) before income taxes	124	79
Net income/(loss)	$ 125	$ 74

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Effective Tax Rate
Income before income taxes	$ 2,307	$ (167)
Income tax expense/(benefit)	$ 571	$ (85)
Effective income tax rate	24.80%	50.90%
Uncertain Tax Benefits
Non-current tax liability for uncertain tax benefits	$ 19
Uncertain tax benefits, penalties and interest accrued	$ 1

XML

Related Party Transactions - Schedule of NRG's Material Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Related Party Transaction [Line Items]
Revenue from related parties	$ 16	$ 15
Gladstone
Related Party Transaction [Line Items]
Revenue from related parties	1	1
Ivanpah
Related Party Transaction [Line Items]
Revenue from related parties	13	12
Midway-Sunset
Related Party Transaction [Line Items]
Revenue from related parties	$ 2	$ 2

XML

Commitments and Contingencies - Narrative (Details)	Mar. 31, 2022 counterparty	Oct. 31, 2021 facility	Jun. 30, 2019 facility	Apr. 30, 2019 case	Feb. 28, 2019 case
Loss Contingencies
Number of facilities | facility		2
Sierra Club Et Al V. Midwest Generation LLC
Loss Contingencies
Number of facilities | facility			4
Direct Energy vs. Stanley, Forte, Schafer and Lane
Loss Contingencies
Pending lawsuits | case				3
Direct Energy vs. Burk and Dickson
Loss Contingencies
Pending lawsuits | case					2
Winter Storm Uri claims vs. Company as power generator
Loss Contingencies
Pending lawsuits | counterparty	161
Winter Storm Uri, claims vs. Company as retail electric provider
Loss Contingencies
Pending lawsuits | counterparty	27

XML

Environmental Matters (Details)	Oct. 31, 2021 facility
Commitments and Contingencies Disclosure [Abstract]
Number of plants	2

XML

Label	Element	Value
Accounting Standards Update [Extensible Enumeration]	us-gaap_AccountingStandardsUpdateExtensibleList	Accounting Standards Update 2020-06 [Member]