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:	June 30, 2024
☐	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 July 31, 2024, there were 206,379,832 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	43
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	78
ITEM 4 — CONTROLS AND PROCEDURES	80
PART II — OTHER INFORMATION	81
ITEM 1 — LEGAL PROCEEDINGS	81
ITEM 1A — RISK FACTORS	81
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	81
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	81
ITEM 4 — MINE SAFETY DISCLOSURES	81
ITEM 5 — OTHER INFORMATION	81
ITEM 6 — EXHIBITS	82
SIGNATURES	83

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," "should," "forecasts," and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which are beyond NRG's control, 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. Forward-looking statements are not guarantees of future results. These factors, risks and uncertainties include the factors described under Risk Factors, in Part II, Item 1A of this Form 10-Q and the following:

•Business uncertainties related to NRG's ability to integrate the operations of Vivint Smart Home;

•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, including the impacts of weather;

•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 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;

•Changes in law, including judicial and regulatory decisions;

•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; and

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

3

In addition, unlisted factors may present significant additional obstacles to the realization of forward-looking statements. 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 except as otherwise required by applicable laws. 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:

2023 Form 10-K	NRG’s Annual Report on Form 10-K for the year ended December 31, 2023
ACE	Affordable Clean Energy
Adjusted EBITDA	Adjusted earnings before interest, taxes, depreciation and amortization
AESO	Alberta Electric System Operator
ASC	The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASR	Accelerated Share Repurchase
ASU	Accounting Standards Updates - updates to the ASC
BTU	British Thermal Unit
Business	NRG Business, which serves business customers
CAA	Clean Air Act
CAISO	California Independent System Operator
CAMT	15% Corporate Alternative Minimum Tax enacted by the IRA on August 16, 2022
CDD	Cooling Degree Day
CFTC	U.S. Commodity Futures Trading Commission
CO2	Carbon Dioxide
Company	NRG Energy, Inc.
Convertible Senior Notes	As of June 30, 2024, consists of NRG’s $232 million unsecured 2.75% Convertible Senior Notes due 2048
Constellation	Constellation Energy Generation
Cottonwood	Cottonwood Generating Station, a natural gas-fueled plant located in Deweyville, Texas, which NRG is leasing through May 2025
CPP	Clean Power Plan
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
EIA	U.S. Energy Information Administration
ELG	Effluent Limitations Guidelines
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
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 solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest
kWh	Kilowatt-hour
LTIPs	Collectively, the NRG long-term incentive plan ("LTIP") and the Vivint 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	Prior to the sale of STP on November 1, 2023, nuclear decommissioning trust fund assets, for NRG's portion of the decommissioning of the STP units 1 & 2
NYISO	New York Independent System Operator
NYMEX	New York Mercantile Exchange
OCI/OCL	Other Comprehensive Income/(Loss)
OECD	Organization for Economic Cooperation and Development
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 $2.3 billion accounts receivables securitization facility due 2025, which was last amended on June 21, 2024
Receivables Securitization Facilities	Collectively, the Receivables Facility and the Repurchase Facility
RECs	Renewable Energy Certificates
Renewable PPA	A third-party PPA entered into directly with a renewable generation facility for the offtake of the Renewable Energy Certificates or other similar environmental attributes generated by such facility, couple with the associated power generated by that facility
REP	Retail electric provider

6

Repurchase Facility	NRG's $150 million uncommitted repurchase facility related to the Receivables Facility due 2024, which was terminated on June 21, 2024
Revolving Credit Facility	The Company's $4.2 billion revolving credit facility due 2028, which was last amended on April 22, 2024
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 Credit Facility	NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the Term Loan B Facility
Senior Notes	As of June 30, 2024, NRG's $3.9 billion outstanding unsecured senior notes consisting of $375 million of the 6.625% senior notes due 2027, $821 million of 5.750% senior notes due 2028, $733 million of the 5.250% 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 $480 million of the 3.875% senior notes due 2032
Senior Secured First Lien Notes	As of June 30, 2024, NRG’s $2.6 billion outstanding Senior Secured First Lien Notes consists of $500 million of the 2.000% Senior Secured First Lien Notes due 2025, $900 million of the 2.450% Senior Secured First Lien Notes due 2027, $500 million of the 4.450% Senior Secured First Lien Notes due 2029 and $740 million of the 7.000% Senior Secured First Lien Notes due 2033
Series A Preferred Stock	As of June 30, 2024, NRG's Series A Preferred Stock consists of 650,000 outstanding shares of the 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, with a $1,000 liquidation preference per share
Services	NRG Services, which primarily includes the services businesses acquired in the Direct Energy acquisition and the Goal Zero business
SO2	Sulfur Dioxide
SOFR	Secured overnight financing rate
STP	South Texas Project — a nuclear generating facility located near Bay City, Texas in which NRG owned a 44% interest. NRG closed on the sale of its interest in STP on November 1, 2023
TDSP	Transmission/distribution service provider
TWh	Terawatt Hour
U.S.	United States of America
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 June 30,				Six months ended June 30,
(In millions, except for per share amounts)	2024		2023		2024		2023
Revenue
Revenue	$	6,659	$	6,348	$	14,088	$	14,070
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)	4,356		4,962		10,041		13,740
Depreciation and amortization	285		315		553		505
Impairment losses	15		—		15		—
Selling, general and administrative costs	592		522		1,183		948
Acquisition-related transaction and integration costs	6		22		15		93
Total operating costs and expenses	5,254		5,821		11,807		15,286
Gain on sale of assets	5		3		1		202
Operating Income/(Loss)	1,410		530		2,282		(1,014)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	4		5		7		10
Other income, net	3		13		33		29
Loss on debt extinguishment	(202)		—		(260)		—
Interest expense	(163)		(151)		(315)		(299)
Total other expense	(358)		(133)		(535)		(260)
Income/(Loss) Before Income Taxes	1,052		397		1,747		(1,274)
Income tax expense/(benefit)	314		89		498		(247)
Net Income/(Loss)	$	738	$	308	$	1,249	$	(1,027)
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		34		21
Net Income/(Loss) Available for Common Stockholders	$	721	$	291	$	1,215	$	(1,048)
Income/(Loss) per Share
Weighted average number of common shares outstanding — basic	208		231		209		230
Income/(Loss) per Weighted Average Common Share — Basic	$	3.47	$	1.26	$	5.81	$	(4.56)
Weighted average number of common shares outstanding — diluted	214		232		214		230
Income/(Loss) per Weighted Average Common Share —Diluted	$	3.37	$	1.25	$	5.68	$	(4.56)

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 June 30,				Six months ended June 30,
(In millions)	2024		2023		2024		2023
Net Income/(Loss)	$	738	$	308	$	1,249	$	(1,027)
Other Comprehensive (Loss)/Income
Foreign currency translation adjustments	(2)		6		(10)		8
Defined benefit plans	(1)		—		(2)		(1)
Other comprehensive (loss)/income	(3)		6		(12)		7
Comprehensive Income/(Loss)	$	735	$	314	$	1,237	$	(1,020)

See accompanying notes to condensed consolidated financial statements.

9

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2024		December 31, 2023
(In millions, except share data)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	376	$	541
Funds deposited by counterparties	688		84
Restricted cash	16		24
Accounts receivable, net	3,402		3,542
Inventory	623		607
Derivative instruments	3,520		3,862
Cash collateral paid in support of energy risk management activities	384		441
Prepayments and other current assets	797		626
Total current assets	9,806		9,727
Property, plant and equipment, net	1,790		1,763
Other Assets
Equity investments in affiliates	45		42
Operating lease right-of-use assets, net	201		179
Goodwill	5,060		5,079
Customer relationships, net	1,946		2,164
Other intangible assets, net	1,467		1,763
Derivative instruments	2,625		2,293
Deferred income taxes	1,841		2,251
Other non-current assets	981		777
Total other assets	14,166		14,548
Total Assets	$	25,762	$	26,038

10

	June 30, 2024		December 31, 2023
(In millions, except share data)	(Unaudited)		(Audited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and finance leases	$	262	$	620
Current portion of operating lease liabilities	91		90
Accounts payable	2,109		2,325
Derivative instruments	2,664		4,019
Cash collateral received in support of energy risk management activities	688		84
Deferred revenue current	779		720
Accrued expenses and other current liabilities	1,709		1,642
Total current liabilities	8,302		9,500
Other Liabilities
Long-term debt and finance leases	10,425		10,133
Non-current operating lease liabilities	144		128
Derivative instruments	1,435		1,488
Deferred income taxes	8		22
Deferred revenue non-current	906		914
Other non-current liabilities	919		947
Total other liabilities	13,837		13,632
Total Liabilities	22,139		23,132
Commitments and Contingencies
Stockholders' Equity
Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at June 30, 2024 and December 31, 2023, aggregate liquidation preference of $650 at June 30, 2024 and December 31, 2023	650		650
Common stock; $0.01 par value; 500,000,000 shares authorized; 266,552,386 and 267,330,470 shares issued and 207,498,428 and 208,130,950 shares outstanding at June 30, 2024 and December 31, 2023, respectively	3		3
Additional paid-in-capital	3,229		3,416
Retained earnings	1,863		820
Treasury stock, at cost; 59,053,958 shares and 59,199,520 shares at June 30, 2024 and December 31, 2023, respectively	(2,019)		(1,892)
Accumulated other comprehensive loss	(103)		(91)
Total Stockholders' Equity	3,623		2,906
Total Liabilities and Stockholders' Equity	$	25,762	$	26,038

See accompanying notes to condensed consolidated financial statements.

11

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended June 30,
(In millions)	2024		2023
Cash Flows from Operating Activities
Net Income/(Loss)	$	1,249	$	(1,027)
Adjustments to reconcile net income/(loss) to cash provided/(used) by operating activities:
Equity in and distributions from earnings of unconsolidated affiliates	(4)		(9)
Depreciation and amortization	553		505
Accretion of asset retirement obligations	3		5
Provision for credit losses	133		80
Amortization of nuclear fuel	—		26
Amortization of financing costs and debt discounts	21		31
Loss on debt extinguishment	260		—
Amortization of in-the-money contracts and emissions allowances	73		112
Amortization of unearned equity compensation	57		61
Net loss/(gain) on sale of assets and disposal of assets	8		(187)
Impairment losses	15		—
Changes in derivative instruments	(1,384)		1,515
Changes in current and deferred income taxes and liability for uncertain tax benefits	390		(282)
Changes in collateral deposits in support of risk management activities	660		(1,355)
Changes in nuclear decommissioning trust liability	—		2
Changes in other working capital	(711)		(505)
Cash provided/(used) by operating activities	$	1,323	$	(1,028)
Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets, net of cash acquired	$	(32)	$	(2,498)
Capital expenditures	(172)		(324)
Net purchases of emissions allowances	(11)		(25)
Investments in nuclear decommissioning trust fund securities	—		(185)
Proceeds from the sale of nuclear decommissioning trust fund securities	—		180
Proceeds from sales of assets, net of cash disposed	11		229
Proceeds from insurance recoveries for property, plant and equipment, net	3		121
Cash used by investing activities	$	(201)	$	(2,502)
Cash Flows from Financing Activities
Proceeds from issuance of preferred stock, net of fees	$	—	$	635
Payments of dividends to preferred and common stockholders	(204)		(174)
Equivalent shares purchased in lieu of tax withholdings	(35)		(16)
Payments for share repurchase activity	(90)		—
Net (payments)/receipts from settlement of acquired derivatives that include financing elements	(12)		318
Net proceeds of Revolving Credit Facility and Receivable Securitization Facilities	—		500
Proceeds from issuance of long-term debt	875		731
Payments of debt issuance costs	(12)		(22)
Repayments of long-term debt and finance leases	(956)		(10)
Payments for debt extinguishment costs	(257)		—
Proceeds from credit facilities	625		1,870
Repayments to credit facilities	(625)		(1,670)
Cash (used)/provided by financing activities	$	(691)	$	2,162
Effect of exchange rate changes on cash and cash equivalents	—		3
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	431		(1,365)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	649		2,178
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	1,080	$	813

See accompanying notes to condensed consolidated financial statements.

12

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

(In millions)	Preferred Stock		Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2023	$	650	$	3	$	3,416	$	820	$	(1,892)	$	(91)	$	2,906
Net income							511						511
Other comprehensive loss											(9)		(9)
Share repurchases(a)					117				(117)				—
Retirement of treasury stock(b)					(38)				38				—
Equity-based awards activity, net(c)					8								8
Common stock dividends and dividend equivalents declared(d)							(86)						(86)
Series A Preferred Stock dividends(e)							(33)						(33)
Balance at March 31, 2024	$	650	$	3	$	3,503	$	1,212	$	(1,971)	$	(100)	$	3,297
Net income							738						738
Other comprehensive loss											(3)		(3)
Shares reissuance for ESPP					1				5				6
Share repurchases(f)									(91)				(91)
Retirement of treasury stock(b)					(38)				38				—
Equity-based awards activity, net(c)					16								16
Common stock dividends and dividend equivalents declared(d)							(87)						(87)
Capped Call Options(g)					(253)								(253)
Balance at June 30, 2024	$	650	$	3	$	3,229	$	1,863	$	(2,019)	$	(103)	$	3,623

(In millions)	Preferred Stock		Common Stock		Additional Paid-In Capital		Retained Earnings/(Accumulated Deficit)		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2022	$	—	$	4	$	8,457	$	1,408	$	(5,864)	$	(177)	$	3,828
Net loss							(1,335)						(1,335)
Issuance of Series A Preferred Stock	650				(14)								636
Other comprehensive income											1		1
Equity-based awards activity, net(c)					38								38
Common stock dividends and dividend equivalents declared(d)							(88)						(88)
Balance at March 31, 2023	$	650	$	4	$	8,481	$	(15)	$	(5,864)	$	(176)	$	3,080
Net income							308						308
Issuance of Series A Preferred Stock					(1)								(1)
Other comprehensive income											6		6
Shares reissuance for ESPP					1				3				4
Equity-based awards activity, net(c)					23								23
Common stock dividends and dividend equivalents declared(d)							(88)						(88)
Balance at June 30, 2023	$	650	$	4	$	8,504	$	205	$	(5,861)	$	(170)	$	3,332

(a)Represents the final settlements of the November 6, 2023 ASR agreements. See Note 9, Changes in Capital Structure for additional information

(b)For further discussion of the treasury stock retirements, see Note 9, Changes in Capital Structure

(c)Includes $(12) million and $(23) million for the quarters ended June 30, and March 31, 2024, respectively, and $(8) million and $(8) million for the quarters ended June 30, and March 31, 2023, respectively, of equivalent shares purchased in lieu of tax withholding on equity compensation issuances

(d)Dividends per common share were $0.4075 for each of the quarters ended June 30 and March 31, 2024 and $0.3775 for each of the quarters ended June 30, and March 31, 2023

(e)Dividend per share of Series A Preferred Stock was $51.25

(f)Includes excise tax accrued of $1 million for the three months ended June 30, 2024

(g)For further discussion of the Capped Call Options, see Note 9, Changes in Capital Structure

See accompanying notes to condensed consolidated financial statements.

13

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, sits at the intersection of energy and home services. NRG is a leading energy and home services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the United States and Canada, NRG delivers innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of generation as of June 30, 2024.

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 customer, plant and market operations in the West and Canada, (ii) the Services businesses and (iii) activity related to the Cottonwood facility and other investments;

•Vivint Smart Home; 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 GAAP 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 2023 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 June 30, 2024, and the results of operations, comprehensive income/(loss), cash flows and stockholders' equity for the three and six months ended June 30, 2024 and 2023.

The Company identified an error in the previously issued condensed consolidated financial statements for the period ended June 30, 2023 related to the presentation of cash flows associated with certain borrowings and repayments related to certain credit facilities. The statement of cash flows for the period ended June 30, 2023 has been adjusted to present on a gross basis the certain borrowings from credit facilities of $1.9 billion and the related repayments of $1.7 billion. The change had no impact to the total cash used by financing activities for the period ended June 30, 2023. The Company evaluated the materiality of this error both qualitatively and quantitatively and has concluded it is immaterial to the impacted period.

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 of operations, net assets or consolidated cash flows.

14

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 customer relationships, net and other intangible assets, net:

(In millions)	June 30, 2024		December 31, 2023
Property, plant and equipment accumulated depreciation	$	1,420	$	1,295
Customer relationships and other intangible assets accumulated amortization	3,319		2,994

Credit Losses

Retail trade receivables are reported on the consolidated balance sheet net of the allowance for credit losses within accounts receivables, net. Long-term receivables are recorded net of allowance for credit losses in other non-current assets on the consolidated balance sheet. 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 and six months ended June 30, 2024 and 2023:

	Three months ended June 30,				Six months ended June 30,
(In millions)	2024		2023		2024		2023
Beginning balance	$	140	$	121	$	145	$	133
Acquired balance from Vivint Smart Home	—		—		—		22
Provision for credit losses	58		45		133		80
Write-offs	(86)		(66)		(178)		(144)
Recoveries collected	9		12		19		21
Other	6		8		8		8
Ending balance	$	127	$	120	$	127	$	120

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)	June 30, 2024		December 31, 2023
Cash and cash equivalents	$	376	$	541
Funds deposited by counterparties	688		84
Restricted cash	16		24
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,080	$	649

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. 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 agreements and funds held within the Company's projects that are restricted in their uses.

15

Goodwill

The following table represents the changes in goodwill during the six months ended June 30, 2024:

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Total
Balance as of December 31, 2023	$	643	$	721	$	221	$	3,494	$	5,079
Impairment	—		—		(15)		—		(15)
Foreign currency translation adjustments	—		—		(4)		—		(4)
Balance as of June 30, 2024	$	643	$	721	$	202	$	3,494	$	5,060

Recent Accounting Developments — Guidance Not Yet Adopted

ASU 2023-07 – In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, or ASU 2023-07. The guidance in ASU 2023-07 enhances reportable segment disclosure requirements by requiring disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit and loss, an amount and description of its composition for other segment items and interim disclosures of a reportable segment’s profit or loss and assets. The Company plans to adopt the new guidance for the annual period ending December 31, 2024 and subsequent interim periods thereafter. The guidance will be applied retrospectively for all prior periods presented in the financial statements.

ASU 2023-09 – In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, or ASU 2023-09. The guidance in ASU 2023-09 enhances income tax disclosures by requiring disclosure of specific categories in the effective tax rate reconciliation and additional information for reconciling items that meet a quantitative threshold. Further the amendments of ASU 2023-09 require certain disclosures on income tax expense and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The amendments of ASU 2023-09 may be applied on a prospective or retrospective basis. The Company is currently evaluating the impact of adopting ASU 2023-09 on its disclosures.

Note 3 — Revenue Recognition

Performance Obligations

As of June 30, 2024, estimated future fixed fee performance obligations are $762 million for the remaining six months of fiscal year 2024, and $1.3 billion, $940 million, $588 million, $308 million and $38 million for the fiscal years 2025, 2026, 2027, 2028 and 2029, respectively. These performance obligations include Vivint Smart Home products and services, as well as cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions. The cleared auction MWs are subject to penalties for non-performance.

16

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three and six months ended June 30, 2024 and 2023:

	Three months ended June 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,766	$	537	$	414	$	467	$	(8)	$	3,176
Business	926		1,824		418		—		—		3,168
Total retail revenue(b)	2,692		2,361		832		467		(8)		6,344
Energy revenue(b)	16		46		51		—		(3)		110
Capacity revenue(b)	—		39		6		—		(1)		44
Mark-to-market for economic hedging activities(c)	—		65		17		—		2		84
Contract amortization	—		(6)		(1)		—		—		(7)
Other revenue(b)	55		27		5		—		(3)		84
Total revenue	2,763		2,532		910		467		(13)		6,659
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		12		19		—		—		31
Less: Realized and unrealized ASC 815 revenue	8		108		32		—		—		148
Total revenue from contracts with customers	$	2,755	$	2,412	$	859	$	467	$	(13)	$	6,480
(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		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	9	$	—	$	—	$	—	$	9
Energy revenue	—		15		16		—		(2)		29
Capacity revenue	—		19		—		—		—		19
Other revenue	8		—		(1)		—		—		7
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

17

	Three months ended June 30, 2023
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,563	$	446	$	406	$	444	$	—	$	2,859
Business	832		1,912		424		—		—		3,168
Total retail revenue(b)	2,395		2,358		830		444		—		6,027
Energy revenue(b)	16		28		40		—		(1)		83
Capacity revenue(b)	—		49		—		—		—		49
Mark-to-market for economic hedging activities(c)	—		52		23		—		—		75
Contract amortization	—		(7)		(1)		—		—		(8)
Other revenue(b)	104		23		—		—		(5)		122
Total revenue	2,515		2,503		892		444		(6)		6,348
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		6		7		—		—		13
Less: Realized and unrealized ASC 815 revenue	14		99		7		—		(1)		119
Total revenue from contracts with customers	$	2,501	$	2,398	$	878	$	444	$	(5)	$	6,216
(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		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	16	$	—	$	—	$	—	$	16
Energy revenue	—		13		(7)		—		(1)		5
Capacity revenue	—		17		—		—		—		17
Other revenue	14		1		(9)		—		—		6
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

	Six months ended June 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	3,126	$	1,239	$	1,013	$	935	$	(8)	$	6,305
Business	1,744		4,550		974		—		—		7,268
Total retail revenue(b)	4,870		5,789		1,987		935		(8)		13,573
Energy revenue(b)	23		127		118		—		(6)		262
Capacity revenue(b)	—		80		8		—		(2)		86
Mark-to-market for economic hedging activities(c)	—		14		8		—		2		24
Contract amortization	—		(16)		(1)		—		—		(17)
Other revenue(b)	103		53		9		—		(5)		160
Total revenue	4,996		6,047		2,129		935		(19)		14,088
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		22		25		—		—		47
Less: Realized and unrealized ASC 815 revenue	10		132		42		—		(3)		181
Total revenue from contracts with customers	$	4,986	$	5,893	$	2,062	$	935	$	(16)	$	13,860
(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		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	19	$	—	$	—	$	—	$	19
Energy revenue	—		58		38		—		(5)		91
Capacity revenue	—		41		—		—		—		41
Other revenue	10		—		(4)		—		—		6
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

18

	Six months ended June 30, 2023
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Retail revenue:
Home(b)	$	2,799	$	1,097	$	1,031	$	592	$	—	$	5,519
Business	1,554		5,277		1,040		—		—		7,871
Total retail revenue(c)	4,353		6,374		2,071		592		—		13,390
Energy revenue(c)	20		102		88		—		1		211
Capacity revenue(c)	—		90		1		—		—		91
Mark-to-market for economic hedging activities(d)	—		87		90		—		(11)		166
Contract amortization	—		(18)		(1)		—		—		(19)
Other revenue(c)	176		44		17		—		(6)		231
Total revenue	4,549		6,679		2,266		592		(16)		14,070
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		5		16		—		—		21
Less: Realized and unrealized ASC 815 revenue	12		212		104		—		(10)		318
Total revenue from contracts with customers	$	4,537	$	6,462	$	2,146	$	592	$	(6)	$	13,731
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Home includes Services
(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		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	43	$	—	$	—	$	—	$	43
Energy revenue	—		60		10		—		1		71
Capacity revenue	—		23		—		—		—		23
Other revenue	12		(1)		4		—		—		15
(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 June 30, 2024 and December 31, 2023:

(In millions)	June 30, 2024		December 31, 2023
Capitalized contract costs (included in Prepayments and other current assets and Other non-current assets)	$	1,005	$	706
Accounts receivable, net - Contracts with customers	3,346		3,395
Accounts receivable, net - Accounted for under topics other than ASC 606	44		136
Accounts receivable, net - Affiliate	12		11
Total accounts receivable, net	$	3,402	$	3,542
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,512	$	1,493
Deferred revenues(a)	1,685		1,634

(a)Deferred revenues from contracts with customers were approximately $1.6 billion as of both June 30, 2024 and December 31, 2023

The revenue recognized from contracts with customers during the three months ended June 30, 2024 and 2023 relating to the deferred revenue balance at the beginning of each period was $266 million and $310 million, respectively, which decreased primarily due to the timing difference of when consideration was received and when the performance obligation was transferred. The revenue recognized from contracts with customers during the six months ended June 30, 2024 and 2023 relating to the deferred revenue balance at the beginning of each period was $395 million and $168 million, respectively, which increased primarily due to the acquisition of Vivint Smart Home.

19

Note 4 — Acquisitions and Dispositions

Acquisitions

Acquisition of Vivint Smart Home

On March 10, 2023, the Company completed the acquisition of Vivint Smart Home, Inc., pursuant to the Agreement and Plan of Merger, dated as of December 6, 2022, by and among the Company, Vivint Smart Home, Inc. and Jetson Merger Sub, Inc., a wholly-owned subsidiary of the Company (“Merger Sub”) pursuant to which Merger Sub merged with and into Vivint Smart Home, Inc., with Vivint Smart Home, Inc. surviving the merger as a wholly-owned subsidiary of the Company. Dedicated to redefining the home experience with intelligent products and services, Vivint Smart Home brought approximately two million subscribers to NRG. Vivint Smart Home's single, expandable platform incorporates artificial intelligence and machine learning into its operating system and its vertically integrated business model includes hardware, software, sales, installation, customer service and technical support and professional monitoring, enabling superior subscriber experiences and a complete end-to-end smart home experience. The acquisition accelerated the realization of NRG's consumer-focused growth strategy and created a leading essential home services platform fueled by market-leading brands, unparalleled insights, proprietary technologies and complementary sales channels.

NRG paid $12 per share, or approximately $2.6 billion in cash. The Company funded the acquisition using:

•proceeds of $724 million from newly issued $740 million 7.000% Senior Secured First Lien Notes due 2033, net of issuance costs and discount;

•proceeds of $635 million from newly issued $650 million 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, net of issuance costs;

•proceeds of approximately $900 million drawn from its Revolving Credit Facility and Receivables Securitization Facilities; and

•cash on hand.

The acquisition has been recorded as a business combination under ASC 805, with identifiable assets and liabilities acquired recorded at their estimated Acquisition Closing Date fair value. The total consideration of $2.623 billion includes:

	(In millions)
Vivint Smart Home, Inc. common shares outstanding as of March 10, 2023 of 216,901,639 at $12.00 per share	$	2,603
Other Vivint Smart Home, Inc. equity instruments (Cash out RSUs and PSUs, Stock Appreciation Rights, Private Placement Warrants)	6
Total Cash Consideration	$	2,609
Fair value of acquired Vivint Smart Home, Inc. equity awards attributable to pre-combination service	14
Total Consideration	$	2,623

Acquisition costs of $2 million and $38 million for the three and six months ended June 30, 2023, respectively, are included in acquisition-related transaction and integration costs in the Company's consolidated statement of operations.

For additional information, refer to Note 4, Acquisitions and Dispositions, to the Company's 2023 Form 10-K.

Dispositions

Planned sale of Airtron

On August 3, 2024, the Company entered into a definitive agreement to sell its Airtron business unit for total proceeds of $500 million, subject to standard purchase price adjustments. Airton is a leading provider of HVAC systems for residential new construction homes and was acquired as part of the Direct Energy acquisition in 2021. The transaction is subject to regulatory approval under the Hart Scott Rodino act and is expected to close by the end of 2024.

Sale of Astoria

On January 6, 2023, the Company closed on the sale of land and related generation assets from the Astoria site, within the East region of operations, for proceeds of $212 million, subject to transaction fees of $3 million and certain indemnifications, resulting in a $199 million gain.

20

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.

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

	June 30, 2024				December 31, 2023
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Convertible Senior Notes	$	232	$	445	$	575	$	739
Other long-term debt, including current portion	10,496		10,142		10,219		9,835
Total long-term debt, including current portion(a)	$	10,728	$	10,587	$	10,794	$	10,574

(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, the Term Loan and Vivint Senior Secured Term Loan are based on quoted market prices and are classified as Level 2 within the fair value hierarchy.

Recurring Fair Value Measurements

Debt securities, 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:

	June 30, 2024
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	25	$	—	$	25	$	—
Derivative assets:
Interest rate contracts	26		—		26		—
Foreign exchange contracts	9		—		9		—
Commodity contracts	6,110		764		5,051		295
Equity securities measured using net asset value practical expedient (classified within other non-current assets)	6
Total assets	$	6,176	$	764	$	5,111	$	295
Derivative liabilities:
Interest rate contracts	$	4	$	—	$	4	$	—
Commodity contracts	3,944		729		3,041		174
Consumer Financing Program	151		—		—		151
Total liabilities	$	4,099	$	729	$	3,045	$	325

21

	December 31, 2023
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	21	$	—	$	21	$	—
Derivative assets:
Interest rate contracts	12		—		12		—
Foreign exchange contracts	5		—		5		—
Commodity contracts	6,138		1,334		4,470		334
Equity securities measured using net asset value practical expedient (classified within other non-current assets)	6
Total assets	$	6,182	$	1,334	$	4,508	$	334
Derivative liabilities:
Interest rate contracts	$	8	$	—	$	8	$	—
Foreign exchange contracts	9		—		9		—
Commodity contracts	5,356		1,413		3,728		215
Consumer Financing Program	134		—		—		134
Total liabilities	$	5,507	$	1,413	$	3,745	$	349

The following table reconciles, for the three and six months ended June 30, 2024 and 2023, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs, for commodity derivatives:

	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Commodity Derivatives(a)
(In millions)	Three months ended June 30, 2024		Three months ended June 30, 2023		Six months ended June 30, 2024		Six months ended June 30, 2023
Beginning balance	$	91	$	471	$	119	$	505
Total gains/(losses) realized/unrealized included in earnings	4		(86)		(37)		(177)
Purchases	31		99		31		140
Transfers into Level 3(b)	2		414		17		438
Transfers out of Level 3(b)	(7)		7		(9)		(1)
Ending balance	$	121	$	905	$	121	$	905
Gains/(losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end	$	8	$	(76)	$	(29)	$	(131)

(a)Consists of derivative assets and liabilities, net, excluding derivatives liabilities from the Consumer Financing Program, which are presented in a separate table below

(b)Transfers into/out of Level 3 within the fair value hierarchy are related to the availability of consensus pricing and external broker quotes and are valued as of the end of the reporting period. All transfers in/out of Level 3 are from/to Level 2

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

22

The following table reconciles, for the three and six months ended June 30, 2024 and 2023, the beginning and ending balances of the contractual obligations from the Consumer Financing Program 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)
	Consumer Financing Program
(In millions)	Three months ended June 30, 2024		Three months ended June 30, 2023		Six months ended June 30, 2024		Six months ended June 30, 2023
Beginning balance	$	(124)	$	(111)	$	(134)	$	—
Contractual obligations added from the acquisition of Vivint Smart Home	—		—		—		(112)
New contractual obligations	(43)		(20)		(58)		(22)
Settlements	22		19		43		22
Total losses included in earnings	(6)		(3)		(2)		(3)
Ending balance	$	(151)	$	(115)	$	(151)	$	(115)

Gains and losses that are related to the Consumer Financing Program derivative are recorded in other income, net.

Derivative Fair Value Measurements

The Company's contracts consist of non-exchange traded contracts valued using prices provided by external sources and exchange-traded contracts with readily available quoted market prices. Beginning in the fourth quarter of 2023 and as of June 30, 2024, the fair value of non-exchange traded contracts were primarily based on consensus pricing provided by independent pricing services. The pricing data was compiled from market makers with longer dated tenors as compared to broker quotes, enhancing reliability and increasing transparency. Prior to the fourth quarter of 2023, the Company valued derivatives based on price quotes from brokers in active markets who regularly facilitate those transactions. 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 June 30, 2024, contracts valued with prices provided by models and other valuation techniques made up 5% of derivative assets and 8% of derivative liabilities.

NRG's significant positions classified as Level 3 include physical and financial natural gas, power, capacity contracts and RECs executed in illiquid markets, FTRs and the Consumer Financing Program. 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. Forward capacity prices are based on market information, forecasted future electricity demand and supply, past auctions and internally developed pricing models. REC prices are based on market information and internally developed pricing models. For FTRs, NRG uses the most recent auction prices to derive the fair value. The Consumer Financing Program derivatives are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates.

23

The following tables quantify the significant, unobservable inputs used in developing the fair value of the Company's Level 3 positions as of June 30, 2024 and December 31, 2023:

	June 30, 2024
	Fair Value						Input/Range
(In millions, except as noted)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	$	39	$	14	Discounted Cash Flow	Forward Market Price ($ per MMBtu)	$	0		$	14		$	4
Power Contracts	168		102		Discounted Cash Flow	Forward Market Price ($ per MWh)	0			188			45
Capacity Contracts	15		12		Discounted Cash Flow	Forward Market Price ($ per MW/Day)	21			641			215
RECs	56		15		Discounted Cash Flow	Forward Market Price ($ per Certificate)	2			248			16
FTRs	17		31		Discounted Cash Flow	Auction Prices ($ per MWh)	(34)			17,974			0
Consumer Financing Program	—		151		Discounted Cash Flow	Collateral Default Rates	1.04		%	66.20		%	9.72		%
					Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.92		%
					Discounted Cash Flow	Credit Loss Rates	4.75		%	60.00		%	13.32		%
	$	295	$	325

	December 31, 2023
	Fair Value						Input/Range
(In millions, except as noted)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	$	39	$	65	Discounted Cash Flow	Forward Market Price ($ per MMBtu)	$	1		$	15		$	3
Power Contracts	197		66		Discounted Cash Flow	Forward Market Price ($ per MWh)	1			210			47
Capacity Contracts	21		33		Discounted Cash Flow	Forward Market Price ($ per MW/Day)	49			658			285
RECs	58		14		Discounted Cash Flow	Forward Market Price ($ per Certificate)	2			320			15
FTRs	19		37		Discounted Cash Flow	Auction Prices ($ per MWh)	(58)			252			0
Consumer Financing Program	—		134		Discounted Cash Flow	Collateral Default Rates	0.43		%	93.30		%	8.12		%
					Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.95		%
					Discounted Cash Flow	Credit Loss Rates	6.00		%	60.00		%	12.57		%
	$	334	$	349

24

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant, unobservable inputs as of June 30, 2024 and December 31, 2023:

Significant Unobservable Input	Position	Change In Input	Impact on Fair Value Measurement
Forward Market Price Natural Gas/Power/Capacity/RECs	Buy	Increase/(Decrease)	Higher/(Lower)
Forward Market Price Natural Gas/Power/Capacity/RECs	Sell	Increase/(Decrease)	Lower/(Higher)
FTR Prices	Buy	Increase/(Decrease)	Higher/(Lower)
FTR Prices	Sell	Increase/(Decrease)	Lower/(Higher)
Collateral Default Rates	n/a	Increase/(Decrease)	Higher/(Lower)
Collateral Prepayment Rates	n/a	Increase/(Decrease)	Lower/(Higher)
Credit Loss Rates	n/a	Increase/(Decrease)	Higher/(Lower)

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 June 30, 2024, the credit reserve resulted in a $7 million decrease primarily within cost of operations. As of December 31, 2023, the credit reserve resulted in a $18 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 2023 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 2023 Form 10-K. As of June 30, 2024, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $2.6 billion and NRG held collateral (cash and letters of credit) against those positions of $1.3 billion, resulting in a net exposure of $1.4 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 61% of the Company's exposure before collateral is expected to roll off by the end of 2025. 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	79	%
Financial institutions	21
Total as of June 30, 2024	100	%

	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	54	%
Non-investment grade/Non-Rated	46
Total as of June 30, 2024	100	%

(a)Counterparty credit exposure excludes 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 exposure to two wholesale counterparties in excess of 10% of total net exposure as of June 30, 2024. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

25

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 under Renewable 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 June 30, 2024, aggregate credit risk exposure managed by NRG to these counterparties was approximately $962 million 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 as well as through Vivint Smart Home, which serve both 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 by using established credit policies, which include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of June 30, 2024, 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 their bills in a timely manner or at all, which could increase customer delinquencies and may lead to an increase in credit losses.

Note 6 — Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of June 30, 2024, NRG had energy-related derivative instruments extending through 2036. The Company marks these derivatives to market through the consolidated statement of operations. NRG has executed energy-related contracts extending through 2036 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

Interest Rate Swaps

NRG is exposed to changes in interest rate through the Company's issuance of variable rate debt. To manage the Company's interest rate risk, NRG enters into interest rate swap agreements. In the first quarter of 2024, the Company entered into interest rate swaps with a total nominal value of $700 million extending through 2029 to hedge the floating rate of the Term Loans (as defined in Note 7, Long-term Debt and Finance Leases). Additionally, as of June 30, 2024, the Company had $1.0 billion of interest rate swaps extending through 2027 to hedge the floating rate on the Vivint Term Loans (as defined in Note 7, Long-term Debt and Finance Leases).

Foreign Exchange Contracts

NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business. To manage the Company's foreign exchange risk, NRG entered into foreign exchange contracts. As of June 30, 2024, NRG had foreign exchange contracts extending through 2027. The Company marks these derivatives to market through the consolidated statement of operations.

26

Consumer Financing Program

Under the Consumer Financing Program, Vivint Smart Home pays a monthly fee to Financing Providers based on either the average daily outstanding balance of the loans or the number of outstanding loans. For certain loans, Vivint Smart Home incurs fees at the time of the loan origination and receives proceeds that are net of these fees. Vivint Smart Home also shares the liability for credit losses, depending on the credit quality of the subscriber. Due to the nature of certain provisions under the Consumer Financing Program, the Company records a derivative liability that is not designated as a hedging instrument and is adjusted to fair value, measured using the present value of the estimated future payments. Changes to the fair value are recorded through other income, net in the consolidated statement of operations. The following represent the contractual future payment obligations with the Financing Providers under the Consumer Financing Program that are components of the derivative:

•    Vivint Smart Home pays either a monthly fee based on the average daily outstanding balance of the loans, or the number of outstanding loans, depending on the Financing Provider;

•    Vivint Smart Home shares the liability for credit losses depending on the credit quality of the subscriber; and

•    Vivint Smart Home pays transactional fees associated with subscriber payment processing.

The derivative is classified as a Level 3 instrument. The derivative positions are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. In summary, the fair value represents an estimate of the present value of the cash flows Vivint Smart Home will be obligated to pay to the Financing Providers for each component of the derivative.

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 June 30, 2024 and December 31, 2023. 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	June 30, 2024	December 31, 2023
RECs	Certificates	14	12
Coal	Short Ton	13	9
Natural Gas	MMBtu	747	838
Power	MWh	208	201
Interest	Dollars	1,700	1,000
Foreign Exchange	Dollars	429	548
Consumer Financing Program	Dollars	1,185	1,116

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)	June 30, 2024		December 31, 2023		June 30, 2024		December 31, 2023
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts - current	$	20	$	12	$	—	$	—
Interest rate contracts - long-term	6		—		4		8
Foreign exchange contracts - current	6		3		—		4
Foreign exchange contracts - long-term	3		2		—		5
Commodity contracts - current	3,494		3,847		2,570		3,922
Commodity contracts - long-term	2,616		2,291		1,374		1,434
Consumer Financing Program - short-term	—		—		94		93
Consumer Financing Program - long-term	—		—		57		41
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	6,145	$	6,155	$	4,099	$	5,507

27

The Company has elected to present derivative assets and liabilities on the consolidated 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 consolidated 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 June 30, 2024
Interest rate contracts:
Derivative assets	$	26	$	(4)	$	—	$	22
Derivative liabilities	(4)		4		—		—
Total interest rate contracts	$	22	$	—	$	—	$	22
Foreign exchange contracts:
Derivative assets	$	9	$	—	$	—	$	9
Commodity contracts:
Derivative assets	$	6,110	$	(3,726)	$	(693)	$	1,691
Derivative liabilities	(3,944)		3,726		47		(171)
Total commodity contracts	$	2,166	$	—	$	(646)	$	1,520
Consumer Financing Program:
Derivative liabilities	$	(151)	$	—	$	—	$	(151)
Total derivative instruments	$	2,046	$	—	$	(646)	$	1,400

	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, 2023
Interest rate contracts:
Derivative assets	$	12	$	(8)	$	—	$	4
Derivative liabilities	(8)		8		—		—
Total interest rate contracts	$	4	$	—	$	—	$	4
Foreign exchange contracts:
Derivative assets	$	5	$	(5)	$	—	$	—
Derivative liabilities	(9)		5		—		(4)
Total foreign exchange contracts	$	(4)	$	—	$	—	$	(4)
Commodity contracts:
Derivative assets	$	6,138	$	(4,926)	$	(74)	$	1,138
Derivative liabilities	(5,356)		4,926		145		(285)
Total commodity contracts	$	782	$	—	$	71	$	853
Consumer Financing Program:
Derivative liabilities	$	(134)	$	—	$	—	$	(134)
Total derivative instruments	$	648	$	—	$	71	$	719

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 consolidated statement of operations. The effect of foreign exchange

28

and commodity hedges are included within revenues and cost of operations. The effect of the interest rate contracts are included within interest expense. The effect of the Consumer Financing Program is included in other income, net.

(In millions)	Three months ended June 30,				Six months ended June 30,
Unrealized mark-to-market results	2024		2023		2024		2023
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	209	$	(151)	$	453	$	(997)
Reversal of acquired loss positions related to economic hedges	17		35		5		10
Net unrealized gains/(losses) on open positions related to economic hedges	649		180		889		(893)
Total unrealized mark-to-market gains/(losses) for economic hedging activities	875		64		1,347		(1,880)
Reversal of previously recognized unrealized losses on settled positions related to trading activity	4		10		—		11
Net unrealized gains on open positions related to trading activity	5		3		5		14
Total unrealized mark-to-market gains for trading activity	9		13		5		25
Total unrealized gains/(losses) - commodities and foreign exchange	$	884	$	77	$	1,352	$	(1,855)

	Three months ended June 30,				Six months ended June 30,
(In millions)	2024		2023		2024		2023
Total impact to statement of operations - interest rate contracts	$	6	$	29	$	18	$	24
Unrealized gains included in revenues - commodities	$	93	$	88	$	29	$	191
Unrealized gains/(losses) included in cost of operations - commodities	789		5		1,312		(2,032)
Unrealized gains/(losses) included in cost of operations - foreign exchange	2		(16)		11		(14)
Total impact to statement of operations - commodities and foreign exchange	$	884	$	77	$	1,352	$	(1,855)
Total impact to statement of operations - Consumer Financing Program	$	(6)	$	(3)	$	(2)	$	(3)

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 six months ended June 30, 2024, the $889 million unrealized gain from open economic hedge positions was primarily the result of an increase in the value of forward positions as a result of increases in ERCOT power prices.

For the six months ended June 30, 2023, the $893 million unrealized loss from open economic hedge positions was primarily the result of a decrease in the value of forward positions as a result of decreases in natural gas and power prices in the East and West.

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 June 30, 2024 was $488 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 $50 million as of June 30, 2024. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $7 million of additional collateral would be required for all contracts with credit rating contingent features as of June 30, 2024.

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

29

Note 7 — Long-term Debt and Finance Leases

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

(In millions, except rates)	June 30, 2024		December 31, 2023		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	480		480		3.875
Convertible Senior Notes, due 2048(a)	232		575		2.750
Senior Secured First Lien Notes, due 2024	—		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
Senior Secured First Lien Notes, due 2033	740		740		7.000
Term Loan, due 2031	873		—		SOFR + 2.000
Tax-exempt bonds	466		466		1.250 - 4.750
Subtotal recourse debt	8,150		8,220
Non-recourse debt:
Vivint Senior Notes, due 2029	800		800		5.750
Vivint Senior Secured Notes, due 2027	600		600		6.750
Vivint Senior Secured Term Loan, due 2028	1,313		1,320		SOFR + 2.750
Subtotal all Vivint non-recourse debt	2,713		2,720
Subtotal long-term debt (including current maturities)	10,863		10,940
Finance leases	21		19		various
Subtotal long-term debt and finance leases (including current maturities)	10,884		10,959
Less current maturities	(262)		(620)
Less debt issuance costs	(62)		(60)
Discounts	(135)		(146)
Total long-term debt and finance leases	$	10,425	$	10,133

(a)As of the ex-dividend date of August 1, 2024, the Convertible Senior Notes were convertible at a price of $41.11, which is equivalent to a conversion rate of approximately 24.322 shares of common stock per $1,000 principal amount

Recourse Debt

Senior Credit Facility

Term Loan B Incurrence

On April 16, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Eighth Amendment to the Second Amended and Restated Credit Agreement (the “Eighth Amendment”) with, among others, Citicorp North America, Inc., as administrative agent (the “Agent”) and as collateral agent, and certain financial institutions, as lenders, which amended the Company’s Second Amended and Restated Credit Agreement, dated as of June 30, 2016 (as amended, restated, supplemented and/or otherwise modified from time to time prior to the effectiveness of the Eighth Amendment, the “Credit Agreement”), in order to (i) establish a new term loan B facility with borrowings of $875 million in aggregate principal amount (the “Term Loan Facility” and the loans thereunder, the “Term Loans”) and (ii) make certain other modifications to the Credit Agreement as set forth therein. The proceeds from the Term Loans were used to repay a portion of the Company’s Convertible Senior Notes, all of the Company’s 3.750% senior secured first lien notes due 2024 and for general corporate purposes.

At the Company’s election, the Term Loans bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate

30

of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Credit Agreement (as amended by the Eighth Amendment and the Ninth Amendment (as defined below))) (after giving effect to any floor applicable to Term SOFR), in each case, plus a margin of 1.00% or (2) Term SOFR (as defined in the Credit Agreement (as amended by the Eighth Amendment and the Ninth Amendment)) (which Term SOFR shall not be less than 0.00%) for a one-, three- or six-month interest period (or such other period as agreed to by the Agent and the lenders, as selected by the Company), plus a margin of 2.00%.

The Term Loan Facility is guaranteed by each of the Company’s subsidiaries that guarantee the Revolving Credit Facility and is secured on a first lien basis by substantially all of the Company’s and such subsidiaries’ assets, in each case, subject to certain customary exceptions and limitations set forth in the Credit Agreement (as amended by the Eighth Amendment and the Ninth Amendment).

The Term Loans have a final maturity date of April 16, 2031 and amortize at a rate of 1% per annum payable in equal quarterly installments. If an event of default occurs under the Term Loan Facility, the entire principal amount outstanding thereunder, together with all accrued unpaid interest and other amounts owing in respect thereof, may be declared immediately due and payable, subject, in certain instances, to the expiration of applicable cure periods. The Term Loan Facility also provides for customary asset sale mandatory prepayments, reporting covenants and negative covenants governing dividends, investments, indebtedness, and other matters that are customary for similar term loan B facilities.

Revolving Credit Facility

On April 22, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement (the “Ninth Amendment”) to extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028.

2048 Convertible Senior Notes

As of July 1, 2024, the Company's Convertible Senior Notes are convertible during the quarterly period ending September 30, 2024 due to the satisfaction of the Common Stock Sale Price Condition (as defined below). As of June 30, 2024, the Convertible Senior Notes are convertible into cash or a combination of cash and the Company’s common stock at a price of $41.32 per common share, which is the equivalent to a conversion rate of approximately 24.1998 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The net carrying amounts of the Convertible Senior Notes as of June 30, 2024 and December 31, 2023 were $231 million and $572 million, respectively. 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, including, among others, during any calendar quarter (and only during such calendar quarter) if the last reported sales price per share of the Company's common stock exceeds 130% of the conversion price for each of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter (the "Common Stock Sale Price Condition"). 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.

All conversions with a conversion date that occurs within the specific periods above will be settled after such period pursuant to the terms of the Convertible Senior Notes indenture.

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

	Three months ended June 30,						Six months ended June 30,
(In millions, except percentages)	2024			2023			2024			2023
Contractual interest expense	$	2		$	4		$	6		$	8
Amortization of deferred finance costs	1			—			1			1
Total	$	3		$	4		$	7		$	9
Effective Interest Rate	0.76		%	0.75		%	1.54		%	1.52		%

31

Repurchases

During the six months ended June 30, 2024, the Company completed repurchases of a portion of the Convertible Senior Notes using cash on hand and a portion of the proceeds from the Term Loans, as detailed in the table below. For the six months ended June 30, 2024, a $260 million loss on debt extinguishment was recorded.

(In millions, except percentages)
Settlement Period	Principal Repurchased		Cash Paid(a)		Average Repurchase Percentage
March 2024	$	92	$	151	162.356%
April 2024	251		452		179.454%
Total Repurchases	$	343	$	603

(a)Includes accrued interest of $1 million and $2 million for the March and April repurchases, respectively

Capped Call Options

During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties (the "Capped Calls") to effectively lock in a conversion premium of $257 million on the remaining $232 million of the Convertible Senior Notes. The option price of $257 million was incurred when the Company entered into the Capped Calls, which will be payable upon the earlier of settlement and expiration of the applicable Capped Calls. For further discussion see Note 9, Changes in Capital Structure.

Receivables Securitization Facilities

On June 21, 2024, NRG Receivables LLC (“NRG Receivables”), an indirect wholly-owned subsidiary of the Company, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 20, 2025, (ii) increase the aggregate commitments from $1.4 billion to $2.3 billion (adjusted seasonally) and (iii) add a new originator. As of June 30, 2024, there were no outstanding borrowings and there were $1.1 billion in letters of credit issued.

Also on June 21, 2024, Direct Energy Services, LLC (in its capacity as additional originator, the “Additional Originator”) entered into a Joinder Agreement (the “Joinder Agreement”) to join as Additional Originator to the Receivables Sale Agreement, dated as of September 22, 2020, among Direct Energy, LP, Direct Energy Business, LLC, Green Mountain Energy Company, NRG Business Marketing, LLC, Reliant Energy Northeast LLC, Reliant Energy Retail Services, LLC, Stream SPE, Ltd., US Retailers LLC and XOOM Energy Texas, LLC, as originators, NRG Retail, as the servicer, and NRG Receivables (the “Receivables Sale Agreement”). Pursuant to the Joinder Agreement, the Additional Originator agrees to be bound by the terms of the Receivables Sale Agreement, will sell to NRG Receivables substantially all of its receivables for the sale of electricity, natural gas and/or related services and certain related rights (collectively, the “Receivables”) and in connection therewith have transferred to NRG Receivables the deposit accounts into which the proceeds of such Receivables are paid.

Concurrently with the amendments to the Receivables Facility, the Company and the originators thereunder terminated the existing uncommitted Repurchase Facility.

Senior Secured First Lien Note Repayment

During the six months ended June 30, 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.

Non-recourse Debt

Vivint Term Loan Repricing

On April 10, 2024, the Company’s wholly-owned indirect subsidiary, APX Group, Inc. (“Vivint”), entered into Amendment No. 2 (the "Second Amendment") to the Second Amended and Restated Credit Agreement dated as of June 9, 2021 (the “Vivint Credit Agreement”) with, among others, Bank of America, N.A. as administrative agent (the “Vivint Agent”), and certain financial institutions, as lenders, which amended the Vivint Agreement in order to (i) reprice its term loan B facility (the term loans thereunder, the “Vivint Term Loans”) and (ii) make certain other changes to the Vivint Credit Agreement.

From and after the closing of the Second Amendment, at Vivint’s election, the Vivint Term Loans will bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Vivint Credit Agreement), (after giving effect to any floor applicable to Term SOFR) plus 1.00% in each case, plus a margin of 1.75%, or (2) Term SOFR (as defined in the Vivint Credit Agreement) (which Term SOFR shall not be less than 0.50%) for a one-, three- or six-month interest period or such other period as agreed to by the Vivint Agent and the lenders, as selected by Vivint, plus a margin of 2.75%.

32

Note 8 — 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 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 2023 Form 10-K.

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

(In millions)	June 30, 2024		December 31, 2023
Accounts receivable and Other current assets	$	2,527	$	1,541
Current liabilities	153		153
Net assets	$	2,374	$	1,388

Note 9 — Changes in Capital Structure

As of June 30, 2024 and December 31, 2023, the Company had 10,000,000 shares of preferred stock authorized and 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's preferred and common stock issued and outstanding:

	Preferred	Common
	Issued and Outstanding	Issued	Treasury	Outstanding
Balance as of December 31, 2023	650,000	267,330,470	(59,199,520)	208,130,950
Shares issued under LTIPs	—	1,499,546	—	1,499,546
Shares issued under ESPP	—	—	145,562	145,562
Shares repurchased	—	—	(2,277,630)	(2,277,630)
Retirement of treasury stock	—	(2,277,630)	2,277,630	—
Balance as of June 30, 2024	650,000	266,552,386	(59,053,958)	207,498,428
Shares issued under LTIPs	—	9,703	—	9,703
Shares repurchased	—	—	(1,127,232)	(1,127,232)
Partial settlement of Capped Call Options	—	—	(1,067)	(1,067)
Retirement of treasury stock	—	(955,232)	955,232	—
Balance as of July 31, 2024	650,000	265,606,857	(59,227,025)	206,379,832

33

Common Stock

Share Repurchases

On June 22, 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of cash available for allocation, after debt reduction, to be returned to shareholders. As part of the revised capital allocation framework, the Company announced an increase to its share repurchase authorization to $2.7 billion, to be executed through 2025. As of July 31, 2024, $1.4 billion is remaining under the $2.7 billion authorization. The following table summarizes the share repurchases made under the $2.7 billion authorization through July 31, 2024:

	Total number of shares purchased	Average price paid per share		Amounts paid for shares purchased (in millions)
2023 Repurchases:
Open market repurchases	5,054,798	$	39.56	$	200
Repurchases made under the accelerated share repurchase agreements	17,676,142	(b)		950
Total Share Repurchases during 2023	22,730,940			1,150		(a)
2024 Repurchases:
Repurchases made under the accelerated share repurchase agreements	1,163,230	(b)		—
Open market repurchases	1,114,400	$	80.76	90
Total Share Repurchases during the six months ended June 30, 2024	2,277,630			$	90	(c)
Open market repurchases July 1, 2024 through July 31, 2024	1,127,232	$	76.27	86
Total Share Repurchases under the $2.7 billion authorization	26,135,802	$	50.73	$	1,326

(a)Excludes $10 million accrued for excise tax owed as of December 31, 2023

(b)Under the November 6, 2023 ASR, the Company received a total of 18,839,372 shares for an average price per share of $50.43, excluding the impact of the excise tax incurred. See discussion below for further information of the ASR agreements

(c)Excludes $1 million accrued for excise tax owed as of June 30, 2024

On November 6, 2023, the Company executed Accelerated Share Repurchase agreements to repurchase a total of $950 million of NRG's outstanding common stock based on volume-weighted average prices. The Company received 17,676,142 shares in the fourth quarter of 2023, which were recorded in treasury stock at fair value based on the closing prices of $833 million, with the remaining $117 million recorded in additional paid-in-capital, representing the value of the forward contracts to purchase additional shares. During the first quarter of 2024, the Company received an additional 1,163,230 shares pursuant to the ASR agreements. Upon receipt of the final shares, the Company transferred the $117 million from additional paid-in-capital to treasury stock.

Employee Stock Purchase Plan

The Company offers 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 90% of its market value on the offering date or 90% 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 2024, NRG increased the annual dividend to $1.63 from $1.51 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.4075 per share was paid on the Company's common stock during the three months ended June 30, 2024. On July 19, 2024, NRG declared a quarterly dividend on the Company's common stock of $0.4075 per share, payable on August 15, 2024 to stockholders of record as of August 1, 2024.

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

34

Retirement of Treasury Stock

During 2024, the Company retired shares of treasury stock as detailed below. These retired shares are now included in NRG's pool of authorized but unissued shares. The Company's accounting policy upon the formal retirement of treasury stock is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from additional paid-in-capital.

	Total number of treasury shares retired	Average price per share		Carrying value of treasury shares retired (in millions)
Shares retired during the first quarter of 2024	1,163,230	$	32.67	$	38
Shares retired during the second quarter of 2024	1,114,400	33.84		38
Total shares retired during the six months ended June 30, 2024	2,277,630			$	76

Capped Call Options

During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties (the "Capped Calls"). The Capped Calls each have a strike price of $41.32 per share, subject to certain adjustments, which correspond to the conversion price of the Convertible Senior Notes as of June 30, 2024. The Capped Calls have a cap price of $249.00 per share, subject to certain adjustments, and effectively lock in a conversion premium of $257 million on the remaining $232 million balance of the Convertible Senior Notes. The options will expire on June 1, 2025 if not exercised. The Capped Calls are separate transactions and not part of the terms of the Convertible Senior Notes. As these transactions meet certain accounting criteria, the Capped Calls are recorded in stockholders' equity. The option price of $257 million incurred in connection with the Capped Calls, of which $253 million was recorded as a reduction to additional paid-in capital and a $4 million loss was recorded to other income, net to account for the change in the value of the Capped Calls during the calculation period which began on May 31, 2024 and concluded on June 28, 2024. The option price will be payable upon the earlier of settlement and expiration of the applicable Capped Calls.

Preferred Stock

Series A Preferred Stock Dividends

During the quarter ended March 31, 2024, the Company declared and paid a semi-annual 10.25% dividend of $51.25 per share on its outstanding Series A Preferred Stock, totaling $33 million.

Note 10 — Income/(Loss) Per Share

Basic income/(loss) per common share is computed by dividing net income/(loss) less cumulative dividends attributable to preferred stock by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the period are weighted for the portion of the period that they were outstanding. Diluted income/(loss) per share is computed in a manner consistent with that of basic income/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period when there is net income. The performance stock units and non-vested restricted stock units are not considered outstanding for purposes of computing basic income/(loss) per share. However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method for periods when there is net income. The Convertible Senior Notes are convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock. 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 there is 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.

35

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

	Three months ended June 30,				Six months ended June 30,
(In millions, except per share data)	2024		2023		2024		2023
Basic income/(loss) per share:
Net income/(loss)	$	738	$	308	$	1,249	$	(1,027)
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		34		21
Net income/(loss) available for common stockholders	$	721	$	291	$	1,215	$	(1,048)
Weighted average number of common shares outstanding - basic	208		231		209		230
Income/(loss) per weighted average common share — basic	$	3.47	$	1.26	$	5.81	$	(4.56)
Diluted income/(loss) per share:
Net income/(loss)	$	738	$	308	$	1,249	$	(1,027)
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		34		21
Net income/(loss) available for common stockholders	$	721	$	291	$	1,215	$	(1,048)
Weighted average number of common shares outstanding - basic	208		231		209		230
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	3		1		2		—
Incremental shares attributable to the potential share settlements of the Convertible Senior Notes (if converted method)	3		—		3		—
Weighted average number of common shares outstanding - dilutive	214		232		214		230
Income/(loss) per weighted average common share — diluted	$	3.37	$	1.25	$	5.68	$	(4.56)

The following table summarizes the Company's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted income/(loss) per share:

	Three months ended June 30,		Six months ended June 30,
(In millions of shares)	2024	2023	2024	2023
Equity compensation plans	—	1	—	7

Note 11 — 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. Vivint Smart Home operations are reported within the Vivint Smart Home segment.

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of the Company's 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). The accounting policies of the segments are the same as those applied in the consolidated financial statements as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company’s 2023 Form 10-K.

36

	Three months ended June 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue	$	2,763	$	2,532	$	910	$	467	$	—	$	(13)	$	6,659
Depreciation and amortization	63		22		46		144		10		—		285
Impairment losses	—		—		15		—		—		—		15
Gain on sale of assets	—		—		5		—		—		—		5
Equity in earnings of unconsolidated affiliates	—		—		4		—		—		—		4
Loss on debt extinguishment	—		—		—		—		(202)		—		(202)
Income/(loss) before income taxes	966		447		(4)		(31)		(326)		—		1,052
Net income/(loss)	$	966	$	447	$	2	$	(29)	$	(648)	$	—	$	738

	Three months ended June 30, 2023
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue	$	2,515	$	2,503	$	892	$	444	$	—	$	(6)	$	6,348
Depreciation and amortization	73		30		23		180		9		—		315
Gain on sale of assets	—		3		—		—		—		—		3
Equity in earnings of unconsolidated affiliates	—		—		5		—		—		—		5
Income/(loss) before income taxes	785		(100)		(128)		(23)		(137)		—		397
Net income/(loss)	$	785	$	(101)	$	(129)	$	(23)	$	(224)	$	—	$	308

	Six months ended June 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue	$	4,996	$	6,047	$	2,129	$	935	$	—	$	(19)	$	14,088
Depreciation and amortization	130		45		70		288		20		—		553
Impairment losses	—		—		15		—		—		—		15
(Loss)/ gain on sale of assets	(4)		—		5		—		—		—		1
Equity in earnings of unconsolidated affiliates	—		—		7		—		—		—		7
Loss on debt extinguishment	—		—		—		—		(260)		—		(260)
Income/(loss) before income taxes	1,315		1,027		(79)		(22)		(494)		—		1,747
Net income/(loss)	$	1,315	$	1,028	$	(58)	$	(22)	$	(1,014)	$	—	$	1,249

	Six months ended June 30, 2023
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate		Eliminations		Total
Revenue	$	4,549	$	6,679	$	2,266	$	592	$	—	$	(16)	$	14,070
Depreciation and amortization	148		60		47		232		18		—		505
Gain on sale of assets	—		202		—		—		—		—		202
Equity in earnings of unconsolidated affiliates	—		—		10		—		—		—		10
Income/(loss) before income taxes	1,069		(1,502)		(479)		(62)		(300)		—		(1,274)
Net income/(loss)	$	1,069	$	(1,503)	$	(433)	$	(62)	$	(98)	$	—	$	(1,027)

(a)Includes results of operations following the acquisition date of March 10, 2023

Note 12 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:

	Three months ended June 30,						Six months ended June 30,
(In millions, except rates)	2024			2023			2024			2023
Income/(Loss) before income taxes	$	1,052		$	397		$	1,747		$	(1,274)
Income tax expense/(benefit)	314			89			498			(247)
Effective income tax rate	29.8		%	22.4		%	28.5		%	19.4		%

37

For the three and six months ended June 30, 2024, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense and permanent differences.

For the three months ended June 30, 2023, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense. For the six months ended June 30, 2023, the effective tax rate was lower than the statutory rate of 21%, primarily due to current state tax expense which has an inverted effect and reduces the effective tax rate when applied to year-to-date financial statement losses.

As of June 30, 2024, NRG as an applicable corporation is subject to the CAMT, and has reflected the impact in its current and deferred taxes. There is no CAMT impact to NRG's effective income tax rate. The Company's CAMT liability is significantly impacted by unrealized gains and losses on derivative instruments. NRG will continue to evaluate the impact of the CAMT if further guidance is provided by the U.S. Treasury or the IRS.

Uncertain Tax Benefits

As of June 30, 2024, NRG had a non-current tax liability of $67 million for uncertain tax benefits from positions taken on various federal and state income tax returns inclusive of accrued interest. For the six months ended June 30, 2024, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of June 30, 2024, NRG had cumulative interest and penalties related to these uncertain tax benefits of $3 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 2020. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2015.

Note 13 — Related Party Transactions

NRG provides services to some of its related parties, which 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 services, 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 June 30,				Six months ended June 30,
(In millions)	2024		2023		2024		2023
Revenues from Related Parties Included in Revenue
Gladstone	$	—	$	—	$	1	$	1
Ivanpah(a)	12		21		25		55
Midway-Sunset	1		1		2		2
Total	$	13	$	22	$	28	$	58

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

Note 14 — 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 June 30, 2024, all hedges under the first liens were in-the-money 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 15, Regulatory Matters, and Note 16, Environmental Matters. In addition,

38

legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded accruals and that such difference could be material.

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

Environmental Lawsuits

Sierra club et al. v. Midwest Generation LLC — In 2012, several environmental groups filed a complaint against Midwest Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in groundwater contamination. In June 2019, the IPCB found 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. In 2023, the IPCB held hearings regarding 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 Case

Mirkin v. XOOM Energy (E.D.N.Y. Aug. 2019) — XOOM Energy is a defendant in a putative class action lawsuit pending in New York, alleging that XOOM Energy 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 Court denied XOOM's motion for summary judgment and granted class certification. The Second Circuit denied XOOM's request to appeal the class certification grants. XOOM plans to challenge Mirkin's expert testimony to further hamper Mirkin's ability to support its case. The parties held a court-ordered remediation on March 21, 2024 where the parties did not settle. The parties continue to prepare pre-trial materials for submission to the Court. A trial date has not been scheduled. The Company continues to deny the allegations and is vigorously defending this matter. This matter was known and accrued for at the time of the XOOM acquisition.

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 Direct Energy 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. The Court denied Direct Energy's motion stating the Court does not have the benefit of all of the facts that were in front of the Burk court to issue a similar ruling. On April 12, 2023, the Court granted Direct Energy’s Motion to Transfer Venue, moving to the case to the Southern District of Texas. The parties are proceeding with written discovery; and (2) Matthew Dickson v. Direct Energy (N.D. Ohio Jan. 2018) - 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. Dickson appealed. The Sixth Circuit found that Dickson has standing and reversed the trial court's dismissal of the case. The matter is back at the trial court. The parties conducted fact and expert discovery and submitted its motion for summary judgment in August 2024.

Sales Practice Lawsuit

A Vivint Smart Home competitor has made a claim against Vivint Smart Home alleging, among other things, that Vivint Smart Home's sales representatives used deceptive sales practices. This matter was known and accrued for at the time of the Vivint Smart Home acquisition. CPI Security Systems, Inc. ("CPI") v. Vivint Smart Home, Inc. (W.D.N.C. Sept. 2020) was

39

filed in 2020 went to trial, and in February 2023, the jury issued a verdict against Vivint Smart Home, in favor of CPI for $50 million of compensatory damages and an additional $140 million of punitive damages. Vivint Smart Home has fully briefed the appeal and is awaiting a hearing date to be set. While Vivint Smart Home believes the CPI jury verdict is not legally or factually supported and intends to pursue post judgment remedies and file an appeal, there can be no assurance that such defense efforts will be successful.

Patent Infringement Lawsuit

SB IP Holdings LLC (“Skybell”) v. Vivint Smart Home, Inc. — On October 23, 2023, a jury in the U.S. District Court, Eastern District of Texas, Sherman Division, issued a verdict against the Company in favor of Skybell for $45 million in damages for patent infringement. The patents that were the basis for the claims made by Skybell were ruled invalid by the U.S. International Trade Commission in November 2021. In accordance with advice by legal counsel, the Company does not believe the verdict is legally supported and will pursue post-judgment and appellate remedies along with any other legal options available. This matter was known and accrued for at the time of the Vivint acquisition.

Contract Dispute

STP — In July 2023, the partners in STP, CPS and Austin Energy, initiated a lawsuit and filed to intervene in the license transfer application with the NRC, claiming a right of first refusal exists in relation to the proposed sale of NRG South Texas' 44% interest in STP to Constellation. The parties entered into a settlement agreement in May 2024, and the litigation was dismissed. There was no incremental impact to NRG as a result of the settlement.

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 REP. Most of the lawsuits related to Winter Storm Uri are consolidated into a single multi-district litigation matter in Harris County District Court. NRG's REPs have since been dismissed from the multi-district litigation. As a power generator, the Company is named in various cases with claims ranging from: wrongful death; personal injury only; property damage and personal injury; property damage only; and subrogation. The First Court of Appeals conditionally granted the generators' mandamus relief, ordering the trial court to grant the generator defendants' Motion to Dismiss. The Company expected the Plaintiffs to challenge this ruling. The Company intends to vigorously defend these matters.

Note 15 — Regulatory Matters

Environmental regulatory matters are discussed within Note 16, 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 proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

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

New York State Public Service Commission ("NYSPSC") - Notice of Apparent Violation — The NYSPSC issued an order referred to as the Retail Reset Order in December 2019 that limited ESCO's offers for electric and natural gas to three compliant products: guaranteed savings from the utility default rate, a fixed rate commodity product that is priced at no more than 5% greater than the trailing 12-month average utility supply rate or New York-sourced renewable energy that is at least 50% greater than the prevailing New York Renewable Energy Standard for load serving entities. The order effectively limited ESCO offers to natural gas customers to only the guaranteed savings and capped fixed term compliant products because no equivalent renewable energy product exists for natural gas. NRG took action to comply with the order when it became effective April 16, 2021. On January 8, 2024, the NYSPSC notified eight of NRG's retail energy suppliers (serving both electricity and natural gas) of alleged non-compliance with New York regulatory requirements. Among other items, the notices allege that the NRG suppliers did not transition existing residential customers to one of the three compliant products authorized by the NYSPSC

40

following the effective date of the order. NRG responded to the notices in February 2024. The outcome of this process has the potential to negatively impact the retail business in New York.

Note 16 — 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 use and discharge, and threatened and endangered species including four rules promulgated during the second quarter of 2024. 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

CPP/ACE Rules — The attention in recent years on GHG emissions has resulted in federal and state regulations. In 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 June 30, 2022, the U.S. Supreme Court held that the "generation shifting" approach in the CPP exceeded the powers granted to the EPA by Congress. The Court did not address the related issues of whether the EPA may adopt only measures applied at each source. On May 9, 2024, the EPA promulgated a rule that repealed the ACE rule and significantly revised the manner in which new combustion-turbine and existing steam EGU's GHG emissions will be regulated including capturing and storing/sequestering CO2 in some instances. This rule has been challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The EPA has stated that it will address GHG emissions from existing combustion turbines in a future rule.

Cross-State Air Pollution Rule ("CSAPR") — On March 15, 2023, the EPA signed and released a prepublication version of a final rule that sought to significantly revise the CSAPR to address the good-neighbor obligations of the 2015 ozone NAAQS for 23 states after earlier having disapproved numerous state plans to address the issue. Several states, including Texas, challenged the EPA's disapproval of their state plans. On May 1, 2023, the United States Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of Texas' and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. Several other states are also similarly situated because of similar stays. Nonetheless, on June 5, 2023, the EPA promulgated this rule. On July 31, 2023, the EPA promulgated an interim final rule that addresses the various judicial orders that have stayed several State-Implementation-Plan disapprovals by limiting the effectiveness of certain requirements of the final rule promulgated on June 5, 2023 in Texas and several other states. On June 27, 2024, the U.S. Supreme Court stayed the final rule in the 11 states where the rule had not already been stayed. The Company cannot predict the outcome of the legal challenges to the: (i) various state disapprovals; (ii) the final rule promulgated on June 5, 2023; and (iii) the interim final rule promulgated on July 31, 2023 that seeks to address the judicial orders.

Regional Haze Proposal — In May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If finalized as proposed, it would result in more stringent SO2 limits for two of the Company's coal-fired units in Texas. The Company cannot predict the outcome of this proposal.

Mercury and Air Toxics Standards (“MATS”) — On May 7, 2024, the EPA promulgated a final rule that amends the MATS rule by, among other things, increasing the stringency of the filterable particulate matter standard at coal-burning units. The deadline for complying with this more stringent standard is 2027. Twenty three states have challenged this rule in the D.C. Circuit. Accordingly, the outcome of this rulemaking may be uncertain for several years.

Water

ELG — In 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. In 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

41

two plants that have coal-fired units in Texas. On May 9, 2024, the EPA promulgated a rule that revises the ELG by, among other things, further restricting the discharge of (i) FGD wastewater, (ii) bottom ash transport water, and (iii) combustion residual leachate. The rule was challenged in numerous courts, but the cases have been consolidated in the Eighth Circuit of the United States Court of Appeals. The Company expects that the outcome of the legal challenges will be uncertain for several years.

Byproducts

In 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy surface impoundments. 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: 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. On May 8, 2024, the EPA promulgated a rule that establishes requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) coal combustion residual ("CCR") management units (regardless of how or when the CCR was placed) at regulated facilities. The rule also creates an obligation to conduct site assessments (at all active and certain inactive facilities) to determine whether CCR management units are present. The rule has been challenged in the D.C. Circuit and may be uncertain for several years.

42

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;

•Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, material cash requirements and commitments, and other obligations; 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 and six months ended June 30, 2024 and 2023. Also refer to NRG's 2023 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 Energy, Inc., or NRG or the Company, sits at the intersection of energy and home services. NRG is a leading energy and home services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the U.S. and Canada, NRG delivers innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of generation as of June 30, 2024.

Strategy

NRG's strategy is to maximize stakeholder value by being a leader in the emerging convergence of energy and smart automation in the home and business. Through a diversified supply strategy, the Company sells reliable electricity and natural gas to its customers in the markets it serves, while also providing innovative home solutions to customers. NRG's unique combination of assets and capabilities enables the Company to develop and sell highly differentiated offerings that bring together every day essential services like powering and securing the home through a seamless and integrated experience. This strategy is intended to enable the Company to optimize its unique integrated platform to delight customers, generate recurring cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is a philosophy that underpins and facilitates value creation across NRG's business for its stakeholders. It is an integral piece of NRG's strategy and ties directly to the Company's 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 counterparties in competitive markets and optimizing on additional revenue opportunities through its multiple brands and channels; (ii) offering a variety of energy products and services, including renewable energy solutions and smart home products and services that are differentiated by innovative features, premium service, integrated platforms, sustainability, and loyalty/affinity programs; (iii) excellence in operating performance of its assets; (iv) achieving the optimal mix of supply to serve its customer load requirements through a diversified supply strategy ; and (v) engaging in disciplined and transparent capital allocation.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2023 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 15, 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.

43

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.

State and Provincial Energy Regulation

Maryland Legislation — On May 9, 2024, Maryland Governor Wes Moore signed Senate Bill 1 into law, which restricts the competitive retail electric and natural-gas market in Maryland, affecting residential customers but not commercial and industrial customers. The new law contains provisions which will come into force by January 1, 2025. The legislation imposes a price cap on residential contracts tied to a trailing 12-month historical average of utility rates, with only a limited exception for renewable power products. Renewable products must now have their price pre-approved pursuant to a process to be established and run by the Maryland Public Service Commission and source their renewable electricity certificates from within the PJM region. The law also requires that any variable-price contract not contain a change in price more than once a year, except time-of-use contracts, and limits contract terms to 12 months. It requires affirmative consent for the renewal of customer contracts for renewable power products. The law also imposes licensing requirements on energy salespersons. The law states that it does not impair existing contracts. The Maryland Public Service Commission is expected to conduct rulemakings to determine the details of a variety of the law’s provisions, but timing is not yet certain.

Regional Regulatory Developments

NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments, see Note 15, Regulatory Matters.

Texas

Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — The PUCT continues to analyze and implement multiple options for promoting increased reliability in the wholesale electric market, including the adoption of a reliability standard for resource adequacy and market-based mechanisms to achieve this standard. The Commission is expected to adopt a reliability standard by the end of 2024. During the 88th Regular Session, the Texas Legislature authorized implementation of the Performance Credit Mechanism ("PCM"), which will measure real-time contribution to system reliability and provide compensation for resources to be available, subject to certain "guardrails" such as an absolute annual net cost cap, as part of its adoption of the PUCT Sunset Bill (House Bill 1500). The Texas Legislature also directed the PUCT to implement additional market design changes such as the creation of a new ancillary service called Dispatchable Reliability Reserve Service ("DRRS") to further increase ERCOT's capability to manage net load variability and firming requirements for new generation resources which penalize poor performance during periods of low grid reserves. The PUCT directed ERCOT to implement DRRS as a standalone product which will delay implementation until 2026 or 2027.

Through Senate Bill 2627, the Texas Legislature created the Texas Energy Fund, which received voter approval in November 2023, and will provide grants and low-interest loans (3%) to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT. The PUCT adopted a rule in March 2024, which establishes the application and participation requirements and the process by which the Texas Energy Fund loan proceeds for dispatchable generation in ERCOT will be distributed. The initial window for submitting loan applications was opened on June 1, 2024 and closed on July 27, 2024. NRG, through its subsidiaries, has filed for loan proceeds for three separate projects, totaling more than 1,500 MWs of capacity. The PUCT also adopted a rule for the completion bonus grant program in April 2024, which provides for opportunities for grants of $120,000 per MW for dispatchable generation projects interconnected before June 1, 2026, or $80,000 per MW for dispatchable generation projects interconnected on or after June 1, 2026 but before June 1, 2029, subject to performance requirements. Applications for completion bonus grants can be submitted beginning in January 2025.

Real-time Co-optimization of Energy and Ancillary Services ("RTC") – ERCOT is progressing with a multi-year project to upgrade their systems to co-optimize the dispatch of energy and ancillary services in real-time. The RTC project will also replace the Operating Reserve Demand Curve with demand curves for each ancillary service product which will act as the primary scarcity pricing mechanism when energy or ancillary services are in shortage. ERCOT anticipates commencing market trials for testing the RTC project in Spring 2025 with production go-live in late 2025 or early 2026.

Supreme Court of Texas Ruling on Pricing during Winter Storm Uri — On June 14, 2024, the Supreme Court of Texas issued an order affirming the validity of two orders issued by the PUCT on February 15 and 16, 2021, respectively, governing scarcity pricing in the ERCOT wholesale electricity market during Winter Storm Uri. The Supreme Court's order reversed the judgment of the Third Court of Appeals, which held that the PUCT exceeded its statutory authority by ordering the market price of energy to be set at the high system wide offer cap due to scarcity conditions as a result of firm load shed occurring in ERCOT. In addition to holding that the PUCT's orders were consistent with the agency's statutory authority, the Supreme Court of Texas's order found that the PUCT had substantially complied with the Administrative Procedure Act's procedural rulemaking requirements, which was an issue that the Third Court of Appeals did not reach.

44

Voluntary Mitigation Plan ("VMP") Changes — On March 13, 2023, the PUCT Staff determined that a portion of NRG's VMP should be terminated due to the increase in procurement of ancillary services by ERCOT, specifically non-spin reserve services, following Winter Storm Uri. As such, PUCT Staff terminated part of the VMP for NRG which provides protection from wholesale market power abuse accusations related to offers for ancillary services. NRG agreed with these changes to the VMP. At the March 23, 2023 open meeting, the PUCT approved the amended VMP. In February 2024, NRG filed a notice of intent with the PUCT and terminated its existing VMP as of March 1, 2024.

Lubbock, Texas Transition to Competition — The customers of Lubbock Power and Light ("LP&L"), a municipally owned utility, entered the Texas retail competitive market in March 2024. Starting in January 2024, LP&L customers were able to shop for a REP. Customers who did not select a REP by February 15, 2024 were assigned to one of three default REPs, one of which is Reliant. LP&L customers started transitioning to their chosen REP or a default REP on March 4, 2024.

PJM

Revisions to PJM Local Deliverability Area Reliability Requirement — The Base Residual Auction for the 2024/2025 delivery year commenced on December 7, 2022 and closed on December 13, 2022. On December 19, 2022, PJM announced that it would delay the publication of the auction results. On December 23, 2022, PJM made a filing at FERC to revise the definition of Locational Deliverability Area ("LDA") Reliability Requirement in the Tariff. This would allow PJM to exclude certain resources from the calculation of the Local Deliverability Area Reliability Requirement. On February 21, 2023, FERC accepted PJM's filing. Multiple parties, including NRG, filed for rehearing. Rehearing was denied by operation of law, and multiple parties, including the Company, filed appeals to the Third Circuit Court of Appeals. On March 12, 2024, the court vacated the portion of the FERC orders that allow PJM to apply the Local Deliverability Area Reliability Requirement to the 2024/2025 capacity auction. On March 29, 2024, PJM filed a petition seeking confirmation as to the capacity commitments rules for the 2024/2025 auction. On April 22, 2024, multiple parties filed a complaint seeking to find the revised rate unjust and unreasonable and implement rates consistent with FERC's February 2023 decision, which was denied on July 9, 2024. On May 6, 2024, FERC directed PJM to recalculate the 2024/2025 auction results under the Initial LDA Reliability Requirement rules, and further directed PJM to rerun the Third Incremental Auction. PJM published the revised Base Residual Auction and Third Incremental Auction results on May 8, 2024 and May 23, 2024, respectively. On June 14, 2024, multiple parties filed appeals to the Third Circuit Court of Appeals seeking review of the May 6, 2024 FERC orders approving PJM's petition to restore the original capacity commitment rules for PJM to recalculate the 2024/2025 Base Residual Auction and the rerun of the 2024/2025. As a result, the capacity for the 2024/2025 delivery year in the Delmarva Power and Light South zone resulted in higher prices. This outcome may change depending upon the disposition of the outstanding complaint and appeals.

PJM Base Residual Auction Revisions and Delay — On April 11, 2023, PJM filed, and FERC subsequently approved, to delay the Base Residual Auctions for the 2025/2026 to 2028/2029 delivery years. On October 13, 2023, PJM made two filings proposing to develop market reforms to improve the operation of the capacity market through changes to the Market Seller Offer Cap rules, changes to PJM's resource adequacy risk modeling and capacity accreditation processes, and changes to capacity performance enhancements. On January 30, 2024, FERC accepted certain reforms to PJM's resource adequacy risk modeling and accreditation processes; on February 6, 2024, FERC rejected PJM's proposed changes to certain Market Seller Offer Cap rules and capacity performance enhancements. The approved changes were in effect for the 2025/2026 Base Residual Auction that occurred in July 2024.

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. FERC accepted the rate schedule with a June 1, 2022 effective date, subject to refund and established hearing and settlement procedures. The Company reached settlement with a number of the intervening parties and the settlement agreement was filed at FERC on April 2, 2024 and is pending FERC review. Delmarva Power submitted to PJM and the Maryland Public Service Commission an update on its projected completion date for the transmission upgrades that would eliminate the need for the Indian River RMR. The new anticipated date is in December 2024, which is sooner than originally estimated by PJM.

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, FERC issued an Order, which permitted the PJM May 2021 capacity auction for the 2022/2023 delivery year 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 eliminated the Cost of New Entry-based Market Seller Offer Cap, implemented a limited default cap for certain asset classes based on going-forward costs and provided for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions. On October 4, 2021, as required by the Order, PJM submitted its compliance tariff and 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

45

filed appeals at the Court of Appeals for the D.C. Circuit, and on August 15, 2023, the Court denied the petitions for review. On January 12, 2024, the generator trade association filed a petition for review with the U.S. Supreme Court to overturn the August 15, 2023 judgment. On May 28, 2024, the U.S. Supreme Court denied the petition for review.

Other Regulatory Matters

From time to time, NRG entities may be subject to examinations, investigations and/or enforcement actions by federal, state and provincial licensing agencies and may face the risk of penalties for violation of financial services, consumer protections and other applicable laws and regulations.

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 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 including unit retirements. 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 and continue to be revised by the EPA, including requirements regarding coal ash, GHG emissions, NAAQS revisions and implementation and effluent limitation guidelines. 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 finally resolved. The Company’s environmental matters are described in the Company’s 2023 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 16, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.

Air 

The CAA and related 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. In March 2024, the EPA increased the stringency of the PM2.5 NAAQS. 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 2019, the 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 June 30, 2022, the U.S. Supreme Court held that the "generation shifting" approach in the CPP exceeded the powers granted to the EPA by Congress. The Court did not address the related issues of whether the EPA may adopt only measures applied at each source. On May 9, 2024, the EPA promulgated a rule that repealed the ACE rule and significantly revised the manner in which new combustion-turbine and existing steam EGU's GHG emissions will be regulated including capturing and storing/sequestering CO2 in some instances. This rule has been challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The EPA has stated that it will address GHG emissions from existing combustion turbines in a future rule.

CSAPR — On March 15, 2023, the EPA signed and released a prepublication of a final rule that sought to significantly revise the CSAPR to address the good-neighbor obligations of the 2015 ozone NAAQS for 23 states after earlier having disapproved numerous state plans to address the issue. Several states, including Texas, challenged the EPA's disapproval of their state plans. On May 1, 2023, the United States Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of Texas' and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. Several other states are also similarly situated because of similar stays. Nonetheless, on June 5, 2023, the EPA promulgated this rule. On July 31, 2023, the EPA promulgated an interim final rule that addresses the various judicial orders that have stayed several State-Implementation-Plan disapprovals by limiting the effectiveness of certain requirements of the final rule promulgated on June 5, 2023 in Texas and several other states. On June 27, 2024, the United States Supreme Court stayed the final rule in the 11 states where the rule had not already been stayed. The Company cannot predict the outcome of the

46

legal challenges to the: (i) various state disapprovals; (ii) the final rule promulgated on June 5, 2023; and (iii) the interim final rule promulgated on July 31, 2023 that seeks to address the judicial orders.

Regional Haze Proposal — On May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If finalized as proposed, the rule would result in more stringent SO2 limits for two of the Company's coal-fired units in Texas. The Company cannot predict the outcome of this proposal.

MATS — On May 7, 2024, the EPA promulgated a final rule that amends the MATS rule by, among other things, increasing the stringency of the filterable particulate matter standard at coal-burning units. The deadline for complying with this more stringent standard is 2027. Twenty three states have challenged this rule in the D.C. Circuit. Accordingly, the outcome of this rulemaking may be uncertain for several years.

Byproducts

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On July 30, 2018, the EPA promulgated a rule that amended the 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 surface impoundments. 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. On May 8, 2024, the EPA promulgated a rule that establishes requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) coal combustion residual ("CCR") management units (regardless of how or when the CCR was placed) at regulated facilities. The rule also creates an obligation to conduct site assessments (at all active and certain inactive facilities) to determine whether CCR management units are present. The rule has been challenged in the D.C. Circuit and may be uncertain for several years.

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.

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.

ELG — In 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. In 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. 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 that have coal-fired units in Texas. On May 9, 2024, the EPA promulgated a rule that revises the ELG by, among other things, further restricting the discharge of (i) FGD wastewater, (ii) bottom ash transport water, and (iii) combustion residual leachate. The rule was challenged in numerous courts, but the cases have been consolidated in the Eighth Circuit of the United States Court of Appeals. The Company expects that the outcome of the legal challenges will be uncertain for several years.

Regional Environmental Developments

Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that required 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. NRG has applied for initial operating permits and construction permits (for closure and retrofits) as required by the regulation and is waiting for most of its permits to be issued by the Illinois EPA.

47

Houston Nonattainment for 2008 Ozone Standard — During the fourth quarter of 2022, the EPA changed the Houston area's classification from Serious to Severe nonattainment for the 2008 Ozone Standard. Accordingly, Texas is required to develop a new control strategy and submit it to the EPA.

Significant Events

The following significant events have occurred during 2024 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:

Dispositions

On August 3, 2024, the Company entered into a definitive agreement to sell its Airtron business unit for total proceeds of $500 million, subject to standard purchase price adjustments. Airton is a leading provider of HVAC systems for residential new construction homes and was acquired as part of the Direct Energy acquisition in 2021. The transaction is subject to regulatory approval under the Hart Scott Rodino act and is expected to close by the end of 2024.

Capital Allocation

During the six months ended June 30, 2024, the Company completed $90 million of open market share repurchases at an average price of $80.76 per share. Through July 31, 2024, an additional $86 million share repurchases were executed at an average price of $76.27 per share. See Note 9, Changes in Capital Structure for additional discussion.

On November 6, 2023, the Company executed Accelerated Share Repurchase agreements to repurchase a total of $950 million of NRG's outstanding common stock. The Company received shares of NRG's common stock on specified settlement dates. The ASR program concluded on March 28, 2024, with total of 18,839,372 shares received at an average price of $50.43 per share.

On April 16, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Eighth Amendment with, among others, Citicorp North America, Inc., as administrative agent and as the Agent, and certain financial institutions, as lenders, which amended the Credit Agreement, in order to (i) establish a new Term Loan Facility with borrowings of $875 million in aggregate principal amount and the Term Loans and (ii) make certain other modifications to the Credit Agreement as set forth therein. The proceeds from the Term Loans were used to repay a portion of the Company’s Convertible Senior Notes, all of the Company's 3.750% senior secured first lien notes due 2024 and for general corporate purposes. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Through April 2024, the Company repurchased $343 million in aggregate principal amount of its Convertible Senior Notes, for $603 million, which included the payment of $3 million of accrued interest, using cash on hand and a portion of the proceeds from the Term Loans. For further discussion, see Note 7, Long-term Debt and Finance Leases.

During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties to effectively lock in a conversion premium of $257 million on the remaining $232 million of the Convertible Senior Notes. The option price of $257 million was incurred when the Company entered into the capped call transactions, which will be payable upon the earlier of settlement and expiration of the applicable Capped Call. For further discussion see Note 9, Changes in Capital Structure.

On June 21, 2024, NRG Receivables, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 20, 2025, (ii) increase the aggregate commitments from $1.4 billion to $2.3 billion (adjusted seasonally) and (iii) add a new originator. For further discussion, see Note 7, Long-term Debt and Finance Leases.

During the six months ended June 30, 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.

In the first quarter of 2024, NRG increased the annual common stock dividend to $1.63 from $1.51 per share, representing an 8% increase from 2023. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

Operations

A component of the Company's strategy is to procure mid to long-term generation through power purchase agreements. NRG has entered into Renewable PPAs totaling approximately 1.9 GW with third-party project developers and other counterparties, of which all are operational as of July 31, 2024. The average tenure of these agreements is eleven years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. The total GW procured through Renewable PPAs may be impacted by contract terminations when they occur.

48

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2023 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment, except for the update below:

Load Growth — The electric industry is expected to experience a surge in demand driven primarily by new manufacturing, industrial and data center facilities (inclusive of generative artificial intelligence ("gen AI")). The EIA's 2023 Annual Energy Outlook, combined with external forecasts of gen AI, shows the potential for 500 TWh of incremental load across the U.S. through 2030, as compared to 2023. ERCOT's current long term load forecast shows peak demand increasing from 86 GW in 2024 to 137 GW in 2028. This load growth will require significant planning and construction of new generation and transmission. ERCOT has announced its New Era of Planning effort to prepare for the possibility of very large and rapid load growth.

Texas Development Priorities

NRG continues to evaluate the expansion of flexible dispatchable power plants within the ERCOT market in connection with the creation of the Texas Energy Fund, a loan program created by the Texas Legislature to finance new build of generation assets within their footprint. The Company submitted applications to the Texas Energy Fund to receive financing for the following projects:

Facility	Fuel Type	Net Generation Capacity (MW)
Cedar Bayou 5	Natural Gas	689
Greens Bayou 6	Natural Gas	443
T.H. Wharton	Natural Gas	415
	Total	1,547

Changes in Accounting Standards

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

49

Consolidated Results of Operations

The following table provides selected financial information for the Company:

	Three months ended June 30,						Six months ended June 30,
(In millions)	2024		2023		Change		2024		2023		Change
Revenue
Retail revenue	$	6,344	$	6,027	$	317	$	13,573	$	13,390	$	183
Energy revenue(a)	110		83		27		262		211		51
Capacity revenue(a)	44		49		(5)		86		91		(5)
Mark-to-market for economic hedging activities	84		75		9		24		166		(142)
Contract amortization	(7)		(8)		1		(17)		(19)		2
Other revenues(a)(b)	84		122		(38)		160		231		(71)
Total revenue	6,659		6,348		311		14,088		14,070		18
Operating Costs and Expenses
Cost of fuel	169		227		58		352		390		38
Purchased energy and other cost of sales(c)	4,482		4,282		(200)		9,996		10,284		288
Mark-to-market for economic hedging activities	(791)		11		802		(1,323)		2,046		3,369
Contract and emissions credit amortization(c)	(17)		(18)		(1)		46		90		44
Operations and maintenance	424		361		(63)		794		746		(48)
Other cost of operations	89		99		10		176		184		8
Cost of operations (excluding depreciation and amortization shown below)	4,356		4,962		606		10,041		13,740		3,699
Depreciation and amortization	285		315		30		553		505		(48)
Impairment losses	15		—		(15)		15		—		(15)
Selling, general and administrative costs	592		522		(70)		1,183		948		(235)
Acquisition-related transaction and integration costs	6		22		16		15		93		78
Total operating costs and expenses	5,254		5,821		567		11,807		15,286		3,479
Gain on sale of assets	5		3		2		1		202		(201)
Operating Income/(Loss)	1,410		530		880		2,282		(1,014)		3,296
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	4		5		(1)		7		10		(3)
Other income, net	3		13		(10)		33		29		4
Loss on debt extinguishment	(202)		—		(202)		(260)		—		(260)
Interest expense	(163)		(151)		(12)		(315)		(299)		(16)
Total other expense	(358)		(133)		(225)		(535)		(260)		(275)
Income/(Loss) Before Income Taxes	1,052		397		655		1,747		(1,274)		3,021
Income tax expense/(benefit)	314		89		(225)		498		(247)		(745)
Net Income/(Loss)	$	738	$	308	$	430	$	1,249	$	(1,027)	$	2,276

(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     

50

Management’s discussion of the results of operations for the three months ended June 30, 2024 and 2023

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 June 30, 2024 and 2023.

	Average on Peak Power Price ($/MWh)
	Three months ended June 30,
Region	2024		2023		Change %
Texas
ERCOT - Houston(a)	$	42.05	$	56.54	(26)	%
ERCOT - North(a)	37.07		54.02		(31)	%
East
NY J/NYC(b)	$	35.93	$	32.02	12	%
NEPOOL(b)	34.50		32.55		6	%
COMED (PJM)(b)	29.31		30.00		(2)	%
PJM West Hub(b)	37.75		35.41		7	%
West
MISO - Louisiana Hub(b)	$	30.60	$	35.30	(13)	%
CAISO - SP15(b)	7.97		30.00		(73)	%

(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

Natural Gas Prices

The following table summarizes the average Henry Hub natural gas price for the three months ended June 30, 2024 and 2023:

	Three months ended June 30,
	2024		2023		Change %
($/MMBtu)	$	1.89	$	2.10	(10)	%

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

51

The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2024 and 2023:

	Three months ended June 30, 2024
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	2,692	$	2,361	$	832	$	467	$	(8)	$	6,344
Energy revenue	16		46		51		—		(3)		110
Capacity revenue	—		39		6		—		(1)		44
Mark-to-market for economic hedging activities	—		65		17		—		2		84
Contract amortization	—		(6)		(1)		—		—		(7)
Other revenue(a)	55		27		5		—		(3)		84
Total revenue	2,763		2,532		910		467		(13)		6,659
Cost of fuel	(124)		(25)		(20)		—		—		(169)
Purchased energy and other cost of sales(b)(c)(d)	(1,729)		(2,004)		(689)		(66)		6		(4,482)
Mark-to-market for economic hedging activities	605		203		(15)		—		(2)		791
Contract and emissions credit amortization	(2)		20		(1)		—		—		17
Depreciation and amortization	(63)		(22)		(46)		(144)		(10)		(285)
Gross margin	$	1,450	$	704	$	139	$	257	$	(19)	$	2,531
Less: Mark-to-market for economic hedging activities, net	605		268		2		—		—		875
Less: Contract and emissions credit amortization, net	(2)		14		(2)		—		—		10
Less: Depreciation and amortization	(63)		(22)		(46)		(144)		(10)		(285)
Economic gross margin	$	910	$	444	$	185	$	401	$	(9)	$	1,931
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $840 million, $71 million and $249 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		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	10,528		3,615		498		—		—		14,641
Business electricity sales volume (GWh)	10,180		11,695		2,974		—		—		24,849
Home natural gas sales volume (MDth)	—		5,683		9,922		—		—		15,605
Business natural gas sales volume (MDth)	—		336,160		43,562		—		—		379,722
Average retail Home customer count (in thousands)(a)	2,975		2,189		766		—		—		5,930
Ending retail Home customer count (in thousands)(a)	2,960		2,194		772		—		—		5,926
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,071		—		2,071
Ending Vivint Smart Home subscriber count (in thousands) (b)	—		—		—		2,106		—		2,106
Power generation
GWh sold	4,784		1,033		1,290		—		—		7,107
GWh generated(c)
Coal	2,372		574		—		—		—		2,946
Gas	2,412		—		1,288		—		—		3,700
Oil	—		—		—		—		—		—
Renewables	—		—		2		—		—		2
Total	4,784		574		1,290		—		—		6,648
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments

52

	Three months ended June 30, 2023
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	2,395	$	2,358	$	830	$	444	$	—	$	6,027
Energy revenue	16		28		40		—		(1)		83
Capacity revenue	—		49		—		—		—		49
Mark-to-market for economic hedging activities	—		52		23		—		—		75
Contract amortization	—		(7)		(1)		—		—		(8)
Other revenue(a)	104		23		—		—		(5)		122
Total revenue	2,515		2,503		892		444		(6)		6,348
Cost of fuel	(184)		(15)		(28)		—		—		(227)
Purchased energy and other cost of sales(b)(c)(d)	(1,403)		(2,129)		(714)		(41)		5		(4,282)
Mark-to-market for economic hedging activities	334		(204)		(141)		—		—		(11)
Contract and emissions credit amortization	(3)		23		(2)		—		—		18
Depreciation and amortization	(73)		(30)		(23)		$	(180)	(9)		(315)
Gross margin	$	1,186	$	148	$	(16)	$	223	$	(10)	$	1,531
Less: Mark-to-market for economic hedging activities, net	334		(152)		(118)		—		—		64
Less: Contract and emissions credit amortization, net	(3)		16		(3)		—		—		10
Less: Depreciation and amortization	(73)		(30)		(23)		(180)		(9)		(315)
Economic gross margin	$	928	$	314	$	128	$	403	$	(1)	$	1,772
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $688 million, $56 million and $241 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(e) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	9,799		2,789		509		—		—		13,097
Business electricity sales volume (GWh)	10,028		11,391		2,282		—		—		23,701
Home natural gas sales volume (MDth)	—		7,716		11,582		—		—		19,298
Business natural gas sales volume (MDth)	—		352,007		42,179		—		—		394,186
Average retail Home customer count (in thousands)(a)	2,866		1,850		777		—		—		5,493
Ending retail Home customer count (in thousands)(a)	2,869		1,858		772		—		—		5,499
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		1,965		—		1,965
Ending Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,004		—		2,004
Power generation
GWh sold	7,508		624		1,566		—		—		9,698
GWh generated(c)
Coal	3,690		148		—		—		—		3,838
Gas	1,625		46		1,565		—		—		3,236
Nuclear	2,193		—		—		—		—		2,193
Renewables	—		—		1		—		—		1
Total	7,508		194		1,566		—		—		9,268
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments

53

The following table represents the weather metrics for the three months ended June 30, 2024 and 2023:

	Three months ended June 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2024
CDDs(a)	1,173	431	638
HDDs(a)	31	435	200
2023
CDDs	978	273	502
HDDs	57	479	254
10-year average
CDDs	989	350	554
HDDs	59	538	192

(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 $1.0 billion and economic gross margin increased $159 million during the three months ended June 30, 2024, compared to the same period in 2023.

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

Texas

	(In millions)
Lower gross margin due to the net effect of: •a 12%, or $83 million increase in cost to serve the retail load, driven by higher realized power prices associated with the Company's diversified supply strategy including asset sales in 2023 •an increase in net revenue of $50 million, primarily driven by changes in customer term, product and mix	$	(33)
Higher gross margin due to an increase in load of 510 GWhs, or $12 million, driven by an increase in customer counts and an increase in load of 371 GWhs, or $12 million, from weather	24
Lower gross margin due to market optimization activities	(6)
Other	(3)
Decrease in economic gross margin	$	(18)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	271
Decrease in contract and emissions credit amortization	1
Decrease in depreciation and amortization	10
Increase in gross margin	$	264

54

East

	(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of the Joliet and Astoria asset retirements	$	(6)
Higher electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $2.00 per MWh, or $33 million as well as lower supply costs of $1.25 per MWh, or $17 million, driven primarily by decreases in power prices	50
Higher electric gross margin due to weather	6
Higher electric gross margin due to an increase in customer count and change in customer mix	11
Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $0.40 per Dth, or $148 million, driven primarily by decreases in gas costs, partially offset lower net revenue rates from changes in customer term, product, and mix of $0.30 per Dth, or $99 million	49
Higher gross margin due to an increase in average realized prices at Midwest Generation	24
Other	(4)
Increase in economic gross margin	$	130
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	420
Increase in contract amortization	(2)
Decrease in depreciation and amortization	8
Increase in gross margin	$	556

West/Services/Other

	(In millions)
Higher electric gross margin due to lower supply costs of $21.00 per MWh, or $73 million and changes in customer mix of $4 million, partially offset by lower revenue rates of $16.00 per MWh, or $55 million	$	22
Higher natural gas gross margin due to lower supply costs of $0.55 per Dth, or $29 million, partially offset by lower revenue rates of $0.50 per Dth, or $27 million	2
Higher gross margin at Cottonwood driven by spark spread expansion	26
Higher gross margin from market optimization activities	8
Other	(1)
Increase in economic gross margin	$	57
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	120
Decrease in contract amortization	1
Increase in depreciation and amortization	(23)
Increase in gross margin	$	155

Vivint Smart Home

	(In millions)
Higher gross margin due to an increase in subscribers of $23 million, as well as higher revenue rates of $1.51 per subscriber, or $9 million; partially offset by lower non-recurring sales revenue of $9 million	$	23
Lower gross margin due to an increase in amortized capitalized contract costs in 2024, associated with the fulfillment of subscriber contracts(a)	(21)
Lower gross margin due to recognition of fees associated with licensing products and services	(3)
Other	(1)
Decrease in economic gross margin	$	(2)
Decrease in depreciation and amortization	36
Increase in gross margin	$	34

(a) Capitalized contract costs began accumulating post acquisition and will continue to accumulate as new customers are acquired, leading to an expected increase in amortizations costs over time

55

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 $811 million during the three months ended June 30, 2024, compared to the same period in 2023.

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

	Three months ended June 30, 2024
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	—	$	1	$	2	$	1	$	4
Net unrealized gains on open positions related to economic hedges	—		64		15		1		80
Total mark-to-market gains in revenue	$	—	$	65	$	17	$	2	$	84
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(32)	$	201	$	37	$	(1)	$	205
Reversal of acquired loss positions related to economic hedges	7		8		2		—		17
Net unrealized gains/(losses) on open positions related to economic hedges	630		(6)		(54)		(1)		569
Total mark-to-market gains/(losses) in operating costs and expenses	$	605	$	203	$	(15)	$	(2)	$	791

	Three months ended June 30, 2023
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	$	(2)	$	17	$	(3)	$	12
Net unrealized gains on open positions related to economic hedges	—		54		6		3		63
Total mark-to-market gains in revenue	$	—	$	52	$	23	$	—	$	75
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(39)	$	(73)	$	(54)	$	3	$	(163)
Reversal of acquired loss positions related to economic hedges	11		20		4		—		35
Net unrealized gains/(losses) on open positions related to economic hedges	362		(151)		(91)		(3)		117
Total mark-to-market gains/(losses) in operating costs and expenses	$	334	$	(204)	$	(141)	$	—	$	(11)

`

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 June 30, 2024, the $84 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of East open positions as a result of decreases in PJM power prices. The $791 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions in Texas as a result of increases in ERCOT power prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.

For the three months ended June 30, 2023, the $75 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in natural gas and power prices as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $11 million loss in operating costs and expenses 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 East and West open positions as a result of decreases in natural gas and power prices. This was partially offset by an increase in the value of Texas open positions as a result of increases in ERCOT power prices and the reversal of acquired loss positions.

56

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 June 30, 2024 and 2023. 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 June 30,
(In millions)	2024		2023
Trading (losses)/gains
Realized	$	—	$	(5)
Unrealized	9		13
Total trading gains	$	9	$	8

Operations and Maintenance Expense

Operations and maintenance expense is comprised of the following:

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Three months ended June 30, 2024	$	231	$	80	$	55	$	57	$	1	$	424
Three months ended June 30, 2023	164		89		55		54		(1)		361

Operations and maintenance expense increased by $63 million for the three months ended June 30, 2024, compared to the same period in 2023, due to the following:

	(In millions)
Increase in planned major maintenance expenditures primarily associated with the scope and duration of outages at the Texas coal facilities	$	54
Increase primarily due to the prior year partial property insurance claim for the extended outage at W.A. Parish	48
Decrease primarily due to the sale of STP in November 2023	(38)
Decrease driven by a reduction in deactivation expenditures primarily in the East	(11)
Other	10
Increase in operations and maintenance expense	$	63

Other Cost of Operations

Other cost of operations is comprised of the following:

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Total
Three months ended June 30, 2024	$	57	$	26	$	4	$	2	$	89
Three months ended June 30, 2023	62		34		2		1		99

Other cost of operations for the three months ended June 30, 2024 decreased by $10 million, when compared to the same period in 2023, due to the following:

	(In millions)
Decrease due to the sale of STP in November 2023	$	(10)
Decrease primarily due to lower retail gross receipt taxes in the East	(1)
Other	1
Decrease in other cost of operations	$	(10)

57

Depreciation and Amortization

Depreciation and amortization are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Total
Three months ended June 30, 2024	$	63	$	22	$	46	$	144	$	10	$	285
Three months ended June 30, 2023	73		30		23		180		9		315

Depreciation and amortization decreased by $30 million for the three months ended June 30, 2024, compared to the same period in 2023, primarily due to lower amortization as a result of the expected roll off of the acquired Vivint Smart Home intangibles.

Selling, General and Administrative Costs

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

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Elimination		Total
Three months ended June 30, 2024	$	195	$	150	$	69	$	170	$	8	$	592
Three months ended June 30, 2023	173		136		54		153		6		522

Selling, general and administrative costs increased by $70 million for the three months ended June 30, 2024, compared to the same period in 2023, due to the following:

	(In millions)
Increase in broker fee and commission expenses	$	18
Increase in marketing and media expenses	18
Increase in personnel costs	14
Increase in provision for credit losses due to higher Home retail revenues	13
Decrease due to the sale of STP in November 2023	(3)
Other	10
Increase in selling, general and administrative costs	$	70

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $6 million and $22 million for the three months ended June 30, 2024 and 2023, respectively, include:

	Three months ended June 30,
(In millions)	2024		2023
Vivint Smart Home integration costs	$	5	$	14
Vivint Smart Home acquisition costs	—		2
Other integration costs, primarily related to Direct Energy	1		6
Acquisition-related transaction and integration costs	$	6	$	22

Loss on Debt Extinguishment

A loss on debt extinguishment of $202 million was recorded for the three months ended June 30, 2024, driven by the repurchase of a portion of the Convertible Senior Notes, as further discussed in Note 7, Long-term Debt and Finance Leases.

Interest Expense

Interest expense increased by $12 million for the three months ended June 30, 2024, compared to the same period in 2023, due to a decrease in unrealized gains on interest rate swaps, partially offset by lower interest primarily due to the repayment on the borrowings in connection with the Vivint Smart Home acquisition.

Income Tax Expense

For the three months ended June 30, 2024, income tax expense of $314 million was recorded on pre-tax income of $1.1 billion. For the same period in 2023, an income tax expense of $89 million was recorded on pre-tax income of $397 million. The effective tax rates were 29.8% and 22.4% for the three months ended June 30, 2024 and 2023, respectively.

58

For the three months ended June 30, 2024, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense and permanent differences. For the same period in 2023, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense.

59

Management’s discussion of the results of operations for the six months ended June 30, 2024 and 2023

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2024 and 2023.

	Average on Peak Power Price ($/MWh)
	Six months ended June 30,
Region	2024		2023		Change %
Texas
ERCOT - Houston (a)	$	34.07	$	41.76	(18)	%
ERCOT - North(a)	31.18		40.37		(23)	%
East
NY J/NYC(b)	$	42.13	$	38.71	9	%
NEPOOL(b)	41.00		42.59		(4)	%
COMED (PJM)(b)	29.74		29.89		(1)	%
PJM West Hub(b)	36.75		35.95		2	%
West
MISO - Louisiana Hub(b)	$	29.33	$	32.54	(10)	%
CAISO - SP15(b)	20.69		61.27		(66)	%

(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

Natural Gas Prices

The following table summarizes the average Henry Hub natural gas price for the six months ended June 30, 2024 and 2023:

	Six months ended June 30,
	2024		2023		Change %
($/MMBtu)	$	2.07	$	2.76	(25)	%

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 emissions 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 energy revenue, capacity revenue, retail 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 activities, contract and emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.

60

The following tables present the composition and reconciliation of gross margin and economic gross margin for the six months ended June 30, 2024 and 2023:

	Six months ended June 30, 2024
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	4,870	$	5,789	$	1,987	$	935	$	(8)	$	13,573
Energy revenue	23		127		118		—		(6)		262
Capacity revenue	—		80		8		—		(2)		86
Mark-to-market for economic hedging activities	—		14		8		—		2		24
Contract amortization	—		(16)		(1)		—		—		(17)
Other revenue(a)	103		53		9		—		(5)		160
Total revenue	4,996		6,047		2,129		935		(19)		14,088
Cost of fuel	(245)		(54)		(53)		—		—		(352)
Purchased energy and other cost of sales(b)(c)(d)	(3,216)		(4,956)		(1,717)		(119)		12		(9,996)
Mark-to-market for economic hedging activities	830		605		(110)		—		(2)		1,323
Contract and emissions credit amortization	(2)		(42)		(2)		—		—		(46)
Depreciation and amortization	(130)		(45)		(70)		$	(288)	(20)		(553)
Gross margin	$	2,233	$	1,555	$	177	$	528	$	(29)	$	4,464
Less: Mark-to-market for economic hedging activities, net	830		619		(102)		—		—		1,347
Less: Contract and emissions credit amortization, net	(2)		(58)		(3)		—		—		(63)
Less: Depreciation and amortization	(130)		(45)		(70)		(288)		(20)		(553)
Economic gross margin	$	1,535	$	1,039	$	352	$	816	$	(9)	$	3,733
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $1.6 billion, $136 million and $657 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		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	18,414		7,446		1,140		—		—		27,000
Business electricity sales volume (GWh)	19,740		23,209		6,012		—		—		48,961
Home natural gas sales volume (MDth)	—		30,113		45,042		—		—		75,155
Business natural gas sales volume (MDth)	—		805,824		97,693		—		—		903,517
Average retail Home customer count (in thousands)(a)	2,951		2,174		764		—		—		5,889
Ending retail Home customer count (in thousands)(a)	2,960		2,194		772		—		—		5,926
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,056		—		2,056
Ending Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,106		—		2,106
Power generation
GWh sold	8,315		2,118		2,874		—		—		13,307
GWh generated(c)
Coal	4,936		965		2,871		—		—		8,772
Gas	3,379		—		—		—		—		3,379
Nuclear	—		—		—		—		—		—
Oil	—		3		—		—		—		3
Renewables	—		—		3		—		—		3
Total	8,315		968		2,874		—		—		12,157
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments

61

	Six months ended June 30, 2023
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Retail revenue	$	4,353	$	6,374	$	2,071	$	592	$	—	$	13,390
Energy revenue	20		102		88		—		1		211
Capacity revenue	—		90		1		—		—		91
Mark-to-market for economic hedging activities	—		87		90		—		(11)		166
Contract amortization	—		(18)		(1)		—		—		(19)
Other revenue(b)	176		44		17		—		(6)		231
Total revenue	4,549		6,679		2,266		592		(16)		14,070
Cost of fuel	(296)		(38)		(56)		—		—		(390)
Purchased energy and other cost of sales(c)(d)(e)	(2,658)		(5,706)		(1,871)		(52)		3		(10,284)
Mark-to-market for economic hedging activities	463		(1,994)		(526)		—		11		(2,046)
Contract and emissions credit amortization	(4)		(81)		(5)		—		—		(90)
Depreciation and amortization	(148)		(60)		(47)		$	(232)	(18)		(505)
Gross margin	$	1,906	$	(1,200)	$	(239)	$	308	$	(20)	$	755
Less: Mark-to-market for economic hedging activities, net	463		(1,907)		(436)		—		—		(1,880)
Less: Contract and emissions credit amortization, net	(4)		(99)		(6)		—		—		(109)
Less: Depreciation and amortization	(148)		(60)		(47)		(232)		(18)		(505)
Economic gross margin	$	1,595	$	866	$	250	$	540	$	(2)	$	3,249
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Includes trading gains and losses and ancillary revenues
(c) Includes capacity and emissions credits
(d) Includes $1.3 billion, $105 million and $598 million of TDSP expense in Texas, East and West/Services/Other, respectively
(e) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	17,413		5,868		1,145		—		—		24,426
Business electricity sales volume (GWh)	18,596		21,842		4,675		—		—		45,113
Home natural gas sales volume (MDth)	—		30,111		48,315		—		—		78,426
Business natural gas sales volume (MDth)	—		823,128		93,058		—		—		916,186
Average retail Home customer count (in thousands)(a)	2,868		1,810		781		—		—		5,459
Ending retail Home customer count (in thousands)(a)	2,869		1,858		772		—		—		5,499
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		1,958		—		1,958
Ending Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,004		—		2,004
Power generation
GWh sold	12,694		1,882		2,869		—		—		17,445
GWh generated(c)
Coal	5,771		366		—		—		—		6,137
Gas	2,410		85		2,867		—		—		5,362
Nuclear	4,513		—		—		—		—		4,513
Renewables	—		—		2		—		—		2
Total	12,694		451		2,869		—		—		16,014
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments

62

The following table represents the weather metrics for the six months ended June 30, 2024 and 2023:

	Six months ended June 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2024
CDDs(a)	1,289	463	687
HDDs(a)	916	2,648	1,299
2023
CDDs	1,144	327	575
HDDs	856	2,570	1,413
10-year average
CDDs	1,101	392	605
HDDs	1,037	3,040	1,298

(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 $3.7 billion and economic gross margin increased $484 million, both of which include intercompany sales, during the six months ended June 30, 2024, compared to the same period in 2023.

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

Texas

	(In millions)
Lower gross margin due to the net effect of: •a 13% or $169 million increase in cost to serve the retail load, driven by higher realized power prices associated with the Company's diversified supply strategy including asset sales in 2023 •an increase in net revenue of $68 million, primarily driven by changes in customer term, product and mix	$	(101)
Higher gross margin due to an increase in load of 1.6 TWhs, or $30 million, driven by an increase in customer counts and an increase in load of 515 GWhs, or $17 million, from weather	47
Lower gross margin due to market optimization activities	(6)
Decrease in economic gross margin	$	(60)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	367
Decrease in contract and emissions credit amortization	2
Decrease in depreciation and amortization	18
Increase in gross margin	$	327

63

East

	(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of Joliet and Astoria asset retirements	$	(18)
Higher electric gross margin due to lower supply costs of $3.50 per MWh, or $106 million, driven primarily by decreases in power prices as well as higher net revenue rates as a result of changes in customer term, product and mix of $0.50 per MWh, or $14 million	120
Higher electric gross margin due to an increase in customer count and change in customer mix	30
Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $1.00 per Dth, or $817 million, driven primarily by a decrease in gas costs, partially offset by lower net revenue rates of $0.95 per Dth, or $809 million, from changes in customer term, product, and mix	8
Lower natural gas gross margin due to weather	(4)
Higher gross margin due to an increase in average realized price at Midwest Generation	44
Other	(7)
Increase in economic gross margin	$	173
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	2,526
Decrease in contract amortization	41
Decrease in depreciation and amortization	15
Increase in gross margin	$	2,755

West/Services/Other

	(In millions)
Higher electric gross margin due to a decrease in supply costs of $20.00 per MWh, or $143 million, and changes in customer mix of $8 million, offset by lower revenue rates of $12.50 per MWh, or $89 million	$	62
Higher natural gas gross margin due to lower supply costs of $1.40 per Dth, or $201 million, partially offset by lower revenue rates $1.35 per Dth, or $190 million	11
Higher gross margin at Cottonwood driven by spark spread expansion	38
Lower gross margin from market optimization activities	(8)
Other	(1)
Increase in economic gross margin	$	102
Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges	334
Decrease in contract amortization	3
Increase in depreciation and amortization	(23)
Increase in gross margin	$	416

64

Vivint Smart Home(a)

	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	276
Higher gross margin due to increased subscribers, or $31 million, as well as higher revenue rates of $1.85 per subscriber or $15 million, partially offset by lower non-recurring sales revenue of $12 million	34
Lower gross margin due to an increase in amortized capitalized contract costs in 2024, associated with the fulfillment of subscriber contracts(b)	(28)
Lower gross margin due to recognition of fees associated with licensing products and services	(4)
Other	(2)
Increase in economic gross margin	$	276
Increase in depreciation and amortization	(56)
Increase in gross margin	$	220

(a) Includes results of operations following the acquisition date of March 10, 2023

(b) Capitalized contract costs began accumulating post acquisition and will continue to accumulate as new customers are acquired, leading to an expected increase in amortizations costs over time

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 $3.2 billion during the six months ended June 30, 2024, compared to the same period in 2023.

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

	Six months ended June 30, 2024
(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	$	—	$	(32)	$	(9)	$	2	$	(39)
Net unrealized gains on open positions related to economic hedges	—		46		17		—		63
Total mark-to-market gains in revenue	$	—	$	14	$	8	$	2	$	24
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(118)	$	532	$	80	$	(2)	$	492
Reversal of acquired loss/(gain) positions related to economic hedges	11		(8)		2		—		5
Net unrealized gains/(losses) on open positions related to economic hedges	937		81		(192)		—		826
Total mark-to-market gains/(losses) in operating costs and expenses	$	830	$	605	$	(110)	$	(2)	$	1,323

65

	Six months ended June 30, 2023
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	$	(15)	$	26	$	(6)	$	5
Reversal of acquired (gain) positions related to economic hedges	—		(1)		—		—		(1)
Net unrealized gains on open positions related to economic hedges	—		103		64		(5)		162
Total mark-to-market gains in revenue	$	—	$	87	$	90	$	(11)	$	166
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(118)	$	(555)	$	(335)	$	6	$	(1,002)
Reversal of acquired loss/(gain) positions related to economic hedges	18		(8)		1		—		11
Net unrealized gains/(losses) on open positions related to economic hedges	563		(1,431)		(192)		5		(1,055)
Total mark-to-market gains/(losses) in operating costs and expenses	$	463	$	(1,994)	$	(526)	$	11	$	(2,046)

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 six months ended June 30, 2024, the $24 million gain in revenues from economic hedge positions was primarily driven by an increase in the value of newly executed East open positions and decreases in PJM power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $1.3 billion gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of Texas open positions as a result of increases in ERCOT power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the six months ended June 30, 2023, the $166 million gain in revenues from economic hedge positions was driven by an increase in the value of open positions as a result of decreases in power and natural gas prices. The $2.0 billion loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of East and West open positions as a result of decreases in natural gas and power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. This was partially offset by an increase in the value of Texas open positions as a result of increase in ERCOT power prices and the reversal of acquired loss positions.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the six months ended June 30, 2024 and 2023. 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.

	Six months ended June 30,
(In millions)	2024		2023
Trading gains/(losses)
Realized	$	5	$	(3)
Unrealized	5		25
Total trading gains	$	10	$	22

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Six months ended June 30, 2024	$	417	$	158	$	107	$	111	$	1	$	794
Six months ended June 30, 2023	382		168		126		72		(2)		746

(a) Includes results of operations following the acquisition date of March 10, 2023

66

Operations and maintenance expense increased by $48 million for the six months ended June 30, 2024, compared to the same period in 2023, due to the following:

	(In millions)
Increase in planned major maintenance expenditures associated with the scope and duration of outages at the Texas coal facilities	$	63
Increase primarily due to the prior year partial property insurance claim for the extended outage at W.A. Parish	44
Increase due to the acquisition of Vivint Smart Home in March 2023	36
Decrease primarily due to the sale of STP in November 2023	(82)
Decrease driven by a reduction in deactivation expenditures primarily in the East	(19)
Other	6
Increase in operations and maintenance expense	$	48

Other Cost of Operations

Other Cost of operations are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Total
Six months ended June 30, 2024	$	107	$	58	$	7	$	4	$	176
Six months ended June 30, 2023	111		66		6		1		184

(a) Includes results of operations following the acquisition date of March 10, 2023

Other cost of operations decreased by $8 million for the six months ended June 30, 2024, compared to the same period in 2023, due to the following:

	(In millions)
Decrease primarily due to the sale of STP in November 2023	$	(15)
Increase in retail gross receipt taxes due to higher revenues in Texas partially offset by lower retail gross receipt taxes in the East	4
Other	3
Decrease in other cost of operations	$	(8)

Depreciation and Amortization

Depreciation and amortization expenses are comprised of the following:

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate		Total
Six months ended June 30, 2024	$	130	$	45	$	70	$	288	$	20	$	553
Six months ended June 30, 2023	148		60		47		232		18		505

(a) Includes results of operations following the acquisition date of March 10, 2023

Depreciation and amortization increased by $48 million for the six months ended June 30, 2024, compared to the same period in 2023, primarily due to higher amortization of intangible assets due to the acquisition of Vivint Smart Home in March 2023.

Selling, General and Administrative Costs

Selling, general and administrative costs comprised of the following:

(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Six months ended June 30, 2024	$	389	$	310	$	124	$	336	$	24	$	1,183
Six months ended June 30, 2023	343		285		105		203		12		948

(a) Includes results of operations following the acquisition date of March 10, 2023

67

Total selling, general and administrative costs increased by $235 million for the six months ended June 30, 2024, compared to the same period in 2023, due to the following:

	(In millions)
Increase due to the Vivint Smart Home acquisition in March 2023	$	104
Increase in provision for credit losses due to higher Home retail revenues and customer payment behavior	44
Increase in broker fee and commissions expenses	37
Increase in marketing and media expenses	32
Increase in personnel costs	22
Decrease driven by the sale of STP in November 2023	(6)
Other	2
Increase in selling, general and administrative costs	$	235

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs were $15 million and $93 million for the six months ended June 30, 2024 and 2023, respectively include:

	Six months ended June 30,
(In millions)	2024		2023
Vivint Smart Home integration costs	$	13	$	44
Vivint Smart Home acquisition costs	—		38
Other integration costs, primarily related to Direct Energy	2		11
Acquisition-related transaction and integration costs	$	15	$	93

Gain on Sale of Assets

The gain on sale of assets of $202 million for the six months ended June 30, 2023 was due to the $199 million gain related to the sale of land and related assets from the Astoria site, as well as other assets sales of $3 million.

Loss on Debt Extinguishment

A loss on debt extinguishment of $260 million was recorded for the six months ended June 30, 2024, driven by the repurchase of a portion of the Convertible Senior Notes, as further discussed in Note 7, Long-term Debt and Finance Leases.

Interest Expense

Interest expense increased by $16 million for the six months ended June 30, 2024, compared to the same period in 2023, primarily due to the acquisition of Vivint Smart Home in March 2023.

Income Tax Expense/(Benefit)

For the six months ended June 30, 2024, an income tax expense of $498 million was recorded on a pre-tax income of $1.7 billion. For the same period in 2023, income tax benefit of $247 million was recorded on pre-tax loss of $1.3 billion. The effective tax rates were 28.5% and 19.4% for the six months ended June 30, 2024 and 2023, respectively.

For the six months ended June 30, 2024, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense and permanent differences. For the same period in 2023, NRG's overall effective tax rate was lower than the statutory rate of 21%, primarily due to current state tax expense which has an inverted effect and reduces the overall effective tax rate when applied to year-to-date financial statement losses.

68

Liquidity and Capital Resources

Liquidity Position

As of June 30, 2024 and December 31, 2023, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $5.3 billion and $4.8 billion, respectively, was comprised of the following:

(In millions)	June 30, 2024		December 31, 2023
Cash and cash equivalents	$	376	$	541
Restricted cash - operating	10		21
Restricted cash - reserves(a)	6		3
Total	392		565
Total availability under Revolving Credit Facility and collective collateral facilities(b)	4,950		4,278
Total liquidity, excluding funds deposited by counterparties	$	5,342	$	4,843

(a) Includes reserves primarily for debt service, performance obligations and capital expenditures

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $7.9 billion and $7.4 billion as of June 30, 2024 and December 31, 2023, respectively.

For the six months ended June 30, 2024, total liquidity, excluding funds deposited by counterparties, increased by $499 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at June 30, 2024 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, and to fund other liquidity commitments in the short and long-term. 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 over time primarily through debt reduction and the realization of growth initiatives.

Credit Ratings

On March 18, 2024, Standard and Poor's ("S&P") affirmed the Company's issuer credit rating of BB and changed the rating outlook from Stable to Positive.

Liquidity

The principal sources of liquidity for NRG's operating and capital expenditures are expected to be derived from cash on hand, cash flows from operations and financing arrangements. As described in Note 7, 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, Term Loan Facility, the Receivables Securitization Facilities and tax-exempt bonds. The Company also issues letters of credit through bilateral letter of credit facilities and the P-Caps letter of credit facility. As part of the acquisition of Vivint Smart Home on March 10, 2023, NRG acquired Vivint's existing debt, which includes senior secured notes, senior notes and a senior secured term-loan.

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 in Note 7, Long-term Debt and Finance Leases; (iii) capital expenditures, including maintenance, environmental, and investments and integration; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Note 9, Changes in Capital Structure.

Planned sale of Airtron

On August 3, 2024, the Company entered into a definitive agreement to sell its Airtron business unit for total proceeds of $500 million, subject to standard purchase price adjustments. Airton is a leading provider of HVAC systems for residential new construction homes and was acquired as part of the Direct Energy acquisition in 2021. The transaction is subject to regulatory approval under the Hart Scott Rodino act and is expected to close by the end of 2024.

69

Senior Credit Facility

On April 16, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Eighth Amendment with, among others, Citicorp North America, Inc., as the Agent and as collateral agent, and certain financial institutions, as lenders, which amended the Credit Agreement, in order to (i) establish a new Term Loan Facility with borrowings of $875 million in aggregate principal amount and the Term Loans and (ii) make certain other modifications to the Credit Agreement as set forth therein. The proceeds from the Term Loans were used to repay a portion of the Company’s Convertible Senior notes, all of the Company’s 3.750% senior secured first lien notes due 2024 and for general corporate purposes.

At the Company’s election, the Term Loans bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Credit Agreement) (after giving effect to any floor applicable to Term SOFR), in each case, plus a margin of 1.00% or (2) Term SOFR (as defined in the Credit Agreement) (which Term SOFR shall not be less than 0.00%) for a one-, three- or six-month interest period (or such other period as agreed to by the Agent and the lenders, as selected by the Company), plus a margin of 2.00%.

On April 22, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Ninth Amendment to its Revolving Credit Facility to extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Convertible Senior Notes

As of July 1, 2024, the Company's Convertible Senior Notes are convertible during the quarterly period ending September 30, 2024 due to the satisfaction of the Common Stock Sale Price Condition. For further discussion, see Note 7, Long-term Debt and Finance Leases.

During the six months ended June 30, 2024, the Company completed repurchases of a portion of the Convertible Senior Notes using cash on hand and a portion of the proceeds from the Term Loans, as detailed in the table below. For the six months ended June 30, 2024, a $260 million loss on debt extinguishment was recorded.

(In millions, except percentages)
Settlement Period	Principal Repurchased		Cash Paid(a)		Average Repurchase Percentage
March 2024	$	92	$	151	162.356%
April 2024	251		452		179.454%
Total Repurchases	$	343	$	603

(a)Includes accrued interest of $1 million and $2 million for the March and April repurchases, respectively

During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties. The Capped Calls have a cap price of $249.00 per share, subject to certain adjustments, and effectively lock in a conversion premium of $257 million on the remaining $232 million balance of the Convertible Senior Notes. The option price of $257 million was incurred was incurred when the Company entered into the Capped Calls, which will be payable upon the earlier of settlement and expiration of the applicable Capped Calls. For further discussion see Note 9, Changes in Capital Structure.

Receivables Securitization Facilities

On June 21, 2024, NRG Receivables, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 20, 2025, (ii) increase the aggregate commitments from $1.4 billion to $2.3 billion (adjusted seasonally) and (iii) add a new originator. As of June 30, 2024, there were no outstanding borrowings and there were $1.1 billion in letters of credit issued.

Also on June 21, 2024, the Additional Originator entered into the Joinder Agreement to join as Additional Originator to the Receivables Sale Agreement, dated as of September 22, 2020, among Direct Energy, LP, Direct Energy Business, LLC, Green Mountain Energy Company, NRG Business Marketing, LLC, Reliant Energy Northeast LLC, Reliant Energy Retail Services, LLC, Stream SPE, Ltd., US Retailers LLC and XOOM Energy Texas, LLC, as Originators, NRG Retail, as the servicer, and the Receivables Sale Agreement. Pursuant to the Joinder Agreement, the Additional Originator agrees to be bound by the terms of the Receivables Sale Agreement, will sell to NRG Receivables substantially all of its Receivables and in connection therewith have transferred to NRG Receivables the deposit accounts into which the proceeds of such Receivables are paid.

70

Concurrently with the amendments to the Receivables Facility, the Company and the originators thereunder terminated the existing uncommitted Repurchase Facility.

Senior Secured First Lien Note Repayment

During the six months ended June 30, 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.

Vivint Term Loan Repricing

On April 10, 2024, Vivint, entered into the Second Amendment with, among others, the Vivint Agent, and certain financial institutions, as lenders, which amended the Vivint Credit Agreement, in order to (i) reprice its term loan B facility (the term loans thereunder, the “Vivint Term Loans”) and (ii) make certain other changes to the Vivint Credit Agreement.

From and after the closing of the Second Amendment, at Vivint’s election, the Vivint Term Loans will bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Vivint Credit Agreement), (after giving effect to any floor applicable to Term SOFR) plus 1.00% in each case, plus a margin of 1.75%, or (2) Term SOFR (as defined in the Vivint Credit Agreement) (which Term SOFR shall not be less than 0.50%) for a one-, three- or six-month interest period or such other period as agreed to by the Vivint Agent and the lenders, as selected by Vivint, plus a margin of 2.75%.

Debt Reduction

The Company intends to spend approximately $500 million reducing debt during 2024 to maintain its targeted credit metrics. The Company intends to fund the debt reduction from cash from operations. Through June 30, 2024, as part of the 2024 capital allocation plan, the Company has spent $325 million on the planned debt reduction.

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 June 30, 2024, the Company had total cash collateral outstanding of $384 million and $2.9 billion outstanding in letters of credit to third parties primarily to support its market activities. As of June 30, 2024, total funds deposited by counterparties were $688 million in cash and $801 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 the capacity to grant 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. 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 differ from the hedged prices. As of June 30, 2024, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

71

Capital Expenditures

The following table summarizes the Company's capital expenditures for maintenance, environmental and growth investments for the six months ended June 30, 2024, and the estimated forecast for the remainder of the year.

(In millions)	Maintenance		Environmental		Investments and Integration		Total
Texas	$	101	$	8	$	16	$	125
West/Services/Other	9		—		1		10
Vivint Smart Home	8				2		10
Corporate	8		—		19		27
Total cash capital expenditures for the six months ended June 30, 2024	126		8		38		172
Integration operating expenses and cost to achieve	—		—		32		32
Investments	—		—		90		90
Total cash capital expenditures and investments for the six months ended June 30, 2024	$	126	$	8	$	160	$	294
Estimated cash capital expenditures and investments for the remainder of 2024(a)	184		17		175		376
Estimated full year 2024 cash capital expenditures and investments	$	310	$	25	$	335	$	670

(a)Excludes capital expenditures related to brownfield development projects that were submitted to the Texas Energy Fund

Investments and Integration for the six months ended June 30, 2024 include growth expenditures, integration, small book acquisitions and other investments.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2024 through 2028 required to comply with environmental laws will be approximately $62 million, primarily driven by the cost of complying with ELG at the Company's coal units in Texas.

Share Repurchases

On June 22, 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of cash available for allocation after debt reduction to be returned to shareholders. As part of the revised capital allocation framework, the Company announced an increase to its share repurchase authorization to $2.7 billion, to be executed through 2025.

During the six months ended June 30, 2024, the Company completed $90 million of open market share repurchases at an average price of $80.76 per share. Through July 31, 2024, an additional $86 million of share repurchases were executed at an average price of $76.27 per share. As of July 31, 2024, $1.4 billion is remaining under the $2.7 billion authorization. See Note 9, Changes in Capital Structure for additional discussion.

Common Stock Dividends

During the first quarter of 2024, NRG increased the annual dividend to $1.63 from $1.51 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.4075 per share was paid on the Company's common stock during the three months ended June 30, 2024. On July 19, 2024, NRG declared a quarterly dividend on the Company's common stock of $0.4075 per share, payable on August 15, 2024 to stockholders of record as of August 1, 2024.

Series A Preferred Stock Dividends

During the quarter ended March 31, 2024, the Company declared and paid a semi-annual 10.25% dividend of $51.25 per share on its outstanding Series A Preferred Stock, totaling $33 million.

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 2023 Form 10-K.

72

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. NRG's pro-rata share of non-recourse debt was approximately $461 million as of June 30, 2024. This indebtedness may restrict the ability of Ivanpah to issue dividends or distributions to NRG.

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 2023 Form 10-K. See also Note 7, Long-term Debt and Finance Leases, and Note 14, 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 and six months ended June 30, 2024.

Cash Flow Discussion

The following table reflects the changes in cash flows for the six month ended June 30, 2024 and 2023, respectively:

	Six months ended June 30,
(In millions)	2024		2023		Change
Cash provided/(used) by operating activities	$	1,323	$	(1,028)	$	2,351
Cash used by investing activities	(201)		(2,502)		2,301
Cash (used)/provided by financing activities	(691)		2,162		(2,853)

Cash provided/(used) by operating activities

Changes to 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	$	2,015
Increase in operating income/loss adjusted for other non-cash items	542
Decrease in working capital primarily related to the payout of the Company's annual incentive plan in 2024 reflecting financial outperformance for 2023	(173)
Other	(33)
	$	2,351

Cash used by investing activities

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

	(In millions)
Decrease in cash paid for acquisitions primarily due to the acquisition of Vivint Smart Home in March 2023	$	2,466
Decrease in proceeds from sale of assets primarily due to the sale of the land and related assets from the Astoria site in January 2023	(218)
Decrease in capital expenditures	152
Decrease in insurance proceeds for property, plant and equipment, net	(118)
Increase due to fewer purchases of emissions allowances, net of sales	14
Other	5
	$	2,301

73

Cash (used)/provided by financing activities

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

	(In millions)
Decrease due to repayments of long-term debt and finance leases	$	(946)
Decrease in proceeds from Revolving Credit Facility and Receivables Securitization Facilities in 2023	(700)
Decrease in proceeds due to the issuance of preferred stock in 2023	(635)
Decrease in net receipts from settlement of acquired derivatives	(330)
Decrease primarily due to debt extinguishment costs in 2024	(247)
Increase in proceeds due to the issuance of long-term debt	144
Decrease due to payments for share repurchase activity	(109)
Increase in payments of dividends primarily due to preferred stock	(30)
	$	(2,853)

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

For the six months ended June 30, 2024, the Company had domestic pre-tax book income of $1.8 billion and foreign pre-tax book loss of $100 million. As of December 31, 2023, the Company had cumulative U.S. Federal NOL carryforwards of $8.4 billion, of which $6.4 billion do not have an expiration date, and cumulative state NOL carryforwards of $6.4 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $411 million, most of which do not have an expiration date. In addition to the above NOLs, NRG has a $517 million indefinite carryforward for interest deductions, as well as $317 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 $160 million in 2024. As of June 30, 2024, NRG as an applicable corporation is subject to the CAMT and expects to claim a CAMT credit in future years. The Company has reflected the impact of the CAMT in its current and deferred taxes. There is no CAMT impact to NRG's effective income tax rate.

As of June 30, 2024, the Company has $64 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability of $67 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority.

On December 31, 2021, the OECD released rules which set forth a common approach to a global minimum tax at 15% for multinational companies, which has been enacted into law by certain countries effective for 2024. The Company's preliminary analysis indicates that there is no material impact to the Company's financial statements from these rules.

The Company is no longer subject to U.S. federal income tax examinations for years prior to 2020. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2015.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of June 30, 2024 and December 31, 2023, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.1 billion and $2.5 billion, respectively. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of June 30, 2024 and December 31, 2023 as discussed below.

NOL Carryforwards — As of June 30, 2024, 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 $367 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 2030. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $106 million.

Valuation Allowance — As of June 30, 2024 and December 31, 2023, the Company’s tax-effected valuation allowance was $271 million and $275 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 June 30, 2024, 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 7, 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 to this Form 10-Q for a listing of the Guarantors. These guarantees are both joint and several.

74

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.

The following tables 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 the 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)	Six months ended June 30, 2024
Revenue(a)	$	11,664
Operating income(b)	2,291
Total other expense	(430)
Income before income taxes	1,861
Net Income	1,341

(a)Intercompany transactions with Non-Guarantors of $1 million during the six months ended June 30, 2024

(b)Intercompany transactions with Non-Guarantors including cost of operations of $44 million and selling, general and administrative of $122 million during the six months ended June 30, 2024

The following table presents the summarized balance sheet information:

(In millions)	June 30, 2024
Current assets(a)	$	6,363
Property, plant and equipment, net	1,235
Non-current assets	12,481
Current liabilities(b)	6,844
Non-current liabilities	9,919

(a)Includes intercompany receivables due from Non-Guarantors of $45 million as of June 30, 2024

(b)Includes intercompany payables due to Non-Guarantors of $23 million as of June 30, 2024

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 order to mitigate interest rate risk associated with the issuance of the Company's variable rate debt, NRG enters into interest rate swap agreements. In addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of U.S. dollar denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.

Under Flex Pay, offered by Vivint Smart Home, subscribers pay for smart home products by obtaining financing from a third-party financing provider under the Consumer Financing Program. Vivint Smart Home pays certain fees to the Financing Providers and shares in credit losses depending on the credit quality of the subscriber.

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.

75

The following tables 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 ("ASC 820"). Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values as of June 30, 2024, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2024. 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	(In millions)
Fair Value of Contracts as of December 31, 2023	$	648
Contracts realized or otherwise settled during the period	471
Other changes in fair value	927
Fair Value of Contracts as of June 30, 2024	$	2,046

	Fair Value of Contracts as of June 30, 2024
(In millions)	Maturity
Fair Value Hierarchy Gains/(Losses)	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	$	1	$	36	$	—	$	(2)	$	35
Level 2	868		773		227		173		2,041
Level 3	(13)		(27)		(10)		20		(30)
Total	$	856	$	782	$	217	$	191	$	2,046

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 June 30, 2024, NRG's net derivative asset was $2.0 billion, an increase to total fair value of $1.4 billion as compared to December 31, 2023. This increase was primarily driven by gains in fair value and the 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 or decrease in natural gas prices across the term of the derivative contracts would result in a change of approximately $2.1 billion in the net value of derivatives as of June 30, 2024.

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.

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.

76

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 2023 Form 10-K. There have been no material changes to the Company's critical accounting estimates since the 2023 Form 10-K.

77

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 2023 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 and six months ended June 30, 2024 and 2023:

(In millions)	2024		2023
VaR as of June 30,	$	57	$	62
Three months ended June 30,
Average	$	66	$	63
Maximum	75		78
Minimum	55		46
Six months ended June 30,
Average	$	63	$	67
Maximum	75		82
Minimum	51		46

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 $194 million, as of June 30, 2024, 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 sales. Counterparty credit risk and retail customer credit risk are discussed below. See Note 6, 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 2023 Form 10-K. As of June 30, 2024, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $2.6 billion and NRG held collateral (cash and letters of credit) against those positions of $1.3 billion, resulting in a net exposure of $1.4 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 61% of the Company's exposure before collateral is expected to roll off by the end of 2025. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net

78

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	79	%
Financial institutions	21
Total as of June 30, 2024	100	%

	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	54	%
Non-investment grade/Non-Rated	46
Total as of June 30, 2024	100	%

(a)Counterparty credit exposure excludes 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 exposure to two wholesale counterparties in excess of 10% of total net exposure discussed above as of June 30, 2024. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

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 under Renewable 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 June 30, 2024, aggregate credit risk exposure managed by NRG to these counterparties was approximately $962 million 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 as well as through Vivint Smart Home, which serve both 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, which include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of June 30, 2024, 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 their bills in a timely manner or at all, which could increase customer delinquencies and may lead to an increase in credit losses.

79

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 June 30, 2024, 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 $857 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 $190 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 2024.

Interest Rate Risk

NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combinations of the variable rate debt and the interest rate derivative instrument. NRG's management policies allow the Company to reduce interest rate exposure from variable rate debt obligations. In the first quarter of 2024, the Company entered into interest rate swaps with a total nominal value of $700 million extending through 2029 to hedge the floating rate of the Term Loans. Additionally, as of June 30, 2024, the Company had $1.0 billion of interest rate swaps extending through 2027 to hedge the floating rate on the Vivint Term Loans.

As of June 30, 2024, the fair value and related carrying value of the Company's debt was $10.6 billion and $10.7 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 June 30, 2024 by $535 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 the Company's 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 June 30, 2024, 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 a notional amount of $429 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 June 30, 2024 would have resulted in a decrease of $8 million to net income within the consolidated statement of operations.

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 June 30, 2024 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

80

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through June 30, 2024, see Note 14, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

During the six months ended June 30, 2024, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company's 2023 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 June 30, 2024.

For the three months ended June 30, 2024	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 (in millions)(a)(c)
Month #1
(April 1, 2024 to April 30, 2024)	—	$	—	—	$	1,550
Month #2
(May 1, 2024 to May 31, 2024)	1,114,400	$	80.76	1,114,400	$	1,460
Month #3
(June 1, 2024 to June 30, 2024)	—	$	—	—	$	1,460
Total at June 30, 2024	1,114,400	$	80.76	1,114,400

(a)On June 22, 2023, the Company announced that the Board of Directors has authorized $2.7 billion for share repurchases to be executed through 2025, as part of NRG's long-term capital allocation policy. The program began following the announcement in 2023 and is subject to the availability of excess cash and full visibility of the achievement of the Company's target credit metrics

(b)The average price paid per share excludes excise tax and commissions of $0.015 to $0.02 per share paid in connection with the open market share repurchases

(c)Includes commissions of $0.015 to $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

There have been no events that are required to be reported under this Item.

ITEM 5 — OTHER INFORMATION

During the three months ended June 30, 2024, the following directors or officers of the Company adopted or terminated a 'Rule 10b5-1 trading arrangement' or 'non-Rule 10b5-1 trading arrangement,' as each term is defined in Item 408(a) of Regulation S-K, as described in the table below:

Name	Title	Date Adopted	Character of Trading Arrangement	Aggregate Number of Shares of Common Stock to be Purchased or Sold Pursuant to Trading Arrangement(a)	Duration	Date Terminated
Rasesh Patel	President, NRG Consumer	5/28/2024	Rule 10b5-1 Trading Arrangement	Up to 102,603 shares to be Sold	9/13/2024-5/30/2025	N/A

(a)Potential sales may be subject to certain price limitations set forth in the 10b5-1 plans and therefore actual number of shares sold could vary if certain minimum stock prices are not met

81

ITEM 6 — EXHIBITS

Number	Description	Method of Filing
10.1	Amendment No. 4 to Receivables Loan and Servicing Agreement, dated as of June 21, 2024, among NRG Retail LLC, as Servicer, NRG Receivables LLC, as Borrower, NRG Energy, Inc., as Performance Guarantor, the Conduit Lenders, Committed Lenders, Facility Agents and LC Issuers party thereto, and Royal Bank of Canada, as administrative Agent, and included as Exhibit A-2 thereto a clean, conformed copy of the Receivables Loan and Servicing Agreement.	Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on June 24, 2024.
10.2	Joinder Agreement, dated as of June 21, 2024, by Direct Energy Services, LLC, as an additional originator and consented to by NRG Receivables LLC, as Borrower, NRG Retail LLC, as Servicer, and Royal Bank of Canada, as administrative agent, to the Receivables Sale Agreement, dated as of September 22, 2020, among the Originators from time to time parties thereto, NRG Retail LLC, as Servicer, and NRG Receivables LLC.	Incorporated herein by reference to Exhibit 10.2 to the Registrant's current report on Form 8-K filed on June 24, 2024.
10.3*	The NRG Energy, Inc. Amended and Restated Long-Term Incentive Plan	Filed herewith.
10.4*	Employment Agreement, dated August 1, 2024 by and between NRG Energy, Inc. and Lawrence S. Coben	Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on August 1, 2024.
22.1	List of Guarantor Subsidiaries	Filed herewith.
31.1	Rule 13a-14(a)/15d-14(a) certification of Lawrence S. Coben.	Filed herewith.
31.2	Rule 13a-14(a)/15d-14(a) certification of Woo-Sung Chung.	Filed herewith.
31.3	Rule 13a-14(a)/15d-14(a) certification of G. Alfred Spencer.	Filed herewith.
32	Section 1350 Certification.	Furnished 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.

* Exhibit relates to compensation arrangements.

82

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/ LAWRENCE S. COBEN
	Lawrence S. Coben
	President and Chief Executive Officer (Principal Executive Officer)
	/s/ WOO-SUNG CHUNG
	Woo-Sung Chung
	Chief Financial Officer (Principal Financial Officer)
	/s/ G. ALFRED SPENCER
	G. Alfred Spencer
Date: August 8, 2024	Chief Accounting Officer (Principal Accounting Officer)

83