[10-Q] NRG ENERGY, INC. Quarterly Earnings Report

Q: What were NRG (NRG) Q3 2025 results?

For the quarter ended September 30, 2025, revenue was $7,635 million and net income was $152 million . Operating income was $414 million .

Q: What is NRG (NRG) year-to-date performance in 2025?

For the nine months ended September 30, 2025, revenue was $22,960 million and net income was $798 million .

Q: How many NRG (NRG) shares were outstanding?

As of October 31, 2025 , NRG had 191,639,408 common shares outstanding.

Q: What were NRG’s debt balances as of September 30, 2025?

Outstanding Senior Notes were $6.2 billion , and Senior Secured First Lien Notes were $2.6 billion .

Q: What were NRG’s interest expense and preferred dividends in Q3 2025?

Interest expense was $187 million , and cumulative dividends on Series A Preferred Stock were $17 million .

Q: What was NRG’s cash balance?

Cash and cash equivalents were $732 million as of September 30, 2025 .

Filing Impact

(Moderate)

Filing Sentiment

(Neutral)

Form Type

10-Q

Rhea-AI Filing Summary

NRG Energy, Inc. reported stronger results in its quarterly 10-Q. For the three months ended September 30, 2025, revenue was $7,635 million and net income was $152 million, reversing a loss a year ago as cost of operations declined sharply.

Operating income reached $414 million versus an operating loss in the prior year period. Interest expense was $187 million, and preferred dividends were $17 million. Year-to-date, revenue totaled $22,960 million with net income of $798 million, aided by lower losses on debt extinguishment. Cash and cash equivalents were $732 million as of September 30, 2025.

The company referenced risks and plans including an anticipated acquisition of a portfolio from LS Power. As of October 31, 2025, there were 191,639,408 common shares outstanding. Senior Notes outstanding were $6.2 billion and Senior Secured First Lien Notes were $2.6 billion as of September 30, 2025.

Insights

NRG posted a clean swing to quarterly profitability on lower costs.

NRG delivered Q3 revenue of $7,635 million with operating income of $414 million, a sharp improvement from last year’s operating loss. The main driver was lower cost of operations, which fell year over year, supporting a return to net income of $152 million.

Year-to-date, net income of $798 million benefited from reduced losses on debt extinguishment ($10 million vs. $260 million prior year) and modestly lower interest expense. Liquidity showed cash of $732 million at Sept 30, 2025.

The filing lists outstanding Senior Notes of $6.2 billion and Senior Secured First Lien Notes of $2.6 billion at Sept 30, 2025. The company also references an anticipated LS Power portfolio acquisition; actual financial effects depend on closing and integration terms disclosed in subsequent updates.

11/06/2025 - 03:06 PM

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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:

September 30, 2025

☐

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
Common Stock, par value $0.01	NRG	NYSE Texas

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 October 31, 2025, there were 191,639,408 shares of common stock outstanding, par value $0.01 per share.

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			47
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			81
ITEM 4 — CONTROLS AND PROCEDURES			84
PART II — OTHER INFORMATION			85
ITEM 1 — LEGAL PROCEEDINGS			85
ITEM 1A — RISK FACTORS			85
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			86
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			86
ITEM 4 — MINE SAFETY DISCLOSURES			86
ITEM 5 — OTHER INFORMATION			86
ITEM 6 — EXHIBITS			87
SIGNATURES			88

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," "targets," 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. These factors, risks and uncertainties include any factors described under Risk Factors, in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 and Part II, Item 1A of this Form 10-Q and the following:

•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;

•The imposition of tariffs and escalation of international trade disputes;

•The risk that the anticipated acquisition of a portfolio of natural gas generation and other assets from LS Power (the “LSP Portfolio”) may not be completed in a timely manner or at all;

•The inability of the Company to realize expected benefits from the integration of LSP Portfolio’s assets and businesses;

•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;

•NRG’s ability to successfully complete the development and construction of new generation projects in a timely and cost effective manner;

•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;

•Operational and reputational risks related to the use of AI and the adherence to developing laws and regulations related to the use of AI;

•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;

•The prolonged continuation of the current shutdown of the U.S. federal government;

•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.

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.

GLOSSARY OF TERMS

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


2024 Form 10-K						NRG’s Annual Report on Form 10-K for the year ended December 31, 2024
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

Cedar Bayou 5						Cedar Bayou Unit 5 generation facility, a 689 MW natural gas-fueled combined cycle plant
CFTC						U.S. Commodity Futures Trading Commission

CO2						Carbon Dioxide
Company						NRG Energy, Inc.
CONE						Cost of New Entry
Convertible Senior Notes						NRG’s unsecured 2.750% Convertible Senior Notes due 2048, which were redeemed on July 8, 2025

Cottonwood						Cottonwood Generating Station, a 1,139 MW natural gas-fueled plant. NRG leased and operated the plant through May 2025
CPP						Clean Power Plan

D.C. Circuit						U.S. Court of Appeals for the District of Columbia Circuit
DOJ						U.S. Department of Justice
Dth						Dekatherms
Economic gross margin						Sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuels, purchased energy and other cost of sales
EGU						Electric Generating Unit
ELG						Effluent Limitations Guidelines which are EPA regulations issued under the federal Clean Water Act
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 United States
GHG						Greenhouse Gas
Green Mountain Energy						Green Mountain Energy Company
Greens Bayou 6						Greens Bayou Unit 6 generation facility, a 443 MW natural gas-fueled peaker plant
GW						Gigawatts
GWh						Gigawatt Hours
HDD						Heating Degree Day


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 whether the electricity output measured is gross or net generation and is 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 385 MW solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest
kWh						Kilowatt-hours


LS Power						LS Power Equity Advisors, LLC
LSP Portfolio						The anticipated acquisition of a portfolio of natural gas generation and other assets from LS Power
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
MMDth						Million Dekatherms
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 Rates						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.

NRG Receivables						NRG Receivables LLC, a wholly-owned indirect subsidiary of the Company
NYISO						New York Independent System Operator
NYMEX						New York Mercantile Exchange


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 2026, which was last amended on June 20, 2025
RECs						Renewable Energy Certificates
Renewable PPA						A third-party PPA entered into directly with a renewable generation facility for the offtake of the RECs or other similar environmental attributes generated by such facility, coupled with the associated power generated by that facility

Revolving Credit Facility						The Company's $4.6 billion revolving credit facility due 2029, which was last amended on May 27, 2025


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

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 September 30, 2025, NRG's $6.2 billion outstanding unsecured senior notes consisting of $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, $798 million of the 5.750% senior notes due 2029, $1.0 billion of the 3.625% senior notes due 2031, $480 million of the 3.875% senior notes due 2032, $925 million of the 6.000% senior notes due 2033 and $950 million of the 6.250% senior notes due 2034
Senior Secured First Lien Notes						As of September 30, 2025, 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 September 30, 2025, 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

SO2						Sulfur Dioxide
SOFR						Secured overnight financing rate


TCJA						The Tax Cuts and Jobs Act of 2017
TDSP						Transmission/distribution service provider
TEF						Texas Energy Fund


Texas Generation Portfolio						The acquisition of a portfolio of power generation facilities and other assets from Rockland Capital, LLC
T.H. Wharton						T.H. Wharton generation facility, a 415 MW natural gas-fueled peaker plant
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

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 September 30,				Nine months ended September 30,
(In millions, except per share amounts)	2025		2024		2025		2024
Revenue
Revenue	$	7,635	$	7,223	$	22,960	$	21,311
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)	6,241		7,239		18,431		17,229
Depreciation and amortization	360		352		1,030		1,045
Impairment losses	—		—		—		15
Selling, general and administrative costs (excluding amortization of customer acquisition costs of $78, $55, $211 and $144, respectively, which are included in depreciation and amortization shown separately above)	612		645		1,885		1,739

Acquisition-related transaction and integration costs	8		7		59		22
Total operating costs and expenses	7,221		8,243		21,405		20,050

Gain/(loss) on sale of assets	—		208		(7)		209
Operating Income/(Loss)	414		(812)		1,548		1,470
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	1		6		4		13

Other income, net	10		5		26		38
Loss on debt extinguishment	—		—		(10)		(260)
Interest expense	(187)		(213)		(498)		(528)
Total other expense	(176)		(202)		(478)		(737)
Income/(Loss) Before Income Taxes	238		(1,014)		1,070		733
Income tax expense/(benefit)	86		(247)		272		251


Net Income/(Loss)	$	152	$	(767)	$	798	$	482
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		51		51
Net Income/(Loss) Available for Common Stockholders	$	135	$	(784)	$	747	$	431
Income/(Loss) per Share
Weighted average number of common shares outstanding — basic	193		207		196		207


Income/(Loss) per Weighted Average Common Share — Basic	$	0.70	$	(3.79)	$	3.81	$	2.08
Weighted average number of common shares outstanding — diluted	195		207		201		213


Income/(Loss) per Weighted Average Common Share —Diluted	$	0.69	$	(3.79)	$	3.72	$	2.02

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2025		2024		2025		2024
Net Income/(Loss)	$	152	$	(767)	$	798	$	482
Other Comprehensive (Loss)/Income

Foreign currency translation adjustments	(4)		6		11		(4)

Defined benefit plans	—		(8)		1		(10)
Other comprehensive (loss)/income	(4)		(2)		12		(14)
Comprehensive Income/(Loss)	$	148	$	(769)	$	810	$	468

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2025		December 31, 2024
(In millions, except share data)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	732	$	966
Funds deposited by counterparties	323		199
Restricted cash	30		8
Accounts receivable, net	3,332		3,488

Inventory	452		478
Derivative instruments	1,928		2,686
Cash collateral paid in support of energy risk management activities	358		309

Prepayments and other current assets	969		830


Total current assets	8,124		8,964
Property, plant and equipment, net	3,396		2,021
Other Assets
Equity investments in affiliates	48		45

Operating lease right-of-use assets, net	139		151
Goodwill	5,015		5,011
Customer relationships, net	1,294		1,538
Other intangible assets, net	1,137		1,370

Derivative instruments	1,486		1,710
Deferred income taxes	1,855		2,067
Other non-current assets	1,477		1,145


Total other assets	12,451		13,037
Total Assets	$	23,971	$	24,022


	September 30, 2025		December 31, 2024
(In millions, except share data)	(Unaudited)		(Audited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities

Current portion of long-term debt and finance leases	$	777	$	996

Current portion of operating lease liabilities	36		66
Accounts payable	2,319		2,513

Derivative instruments	1,880		2,297
Cash collateral received in support of energy risk management activities	323		199
Deferred revenue current	710		711
Accrued expenses and other current liabilities	1,668		2,031



Total current liabilities	7,713		8,813
Other Liabilities
Long-term debt and finance leases	11,155		9,812
Non-current operating lease liabilities	143		117



Derivative instruments	1,125		1,107
Deferred income taxes	12		12
Deferred revenue non-current	942		862
Other non-current liabilities	911		821


Total other liabilities	14,288		12,731
Total Liabilities	22,001		21,544

Commitments and Contingencies
Stockholders' Equity
Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at September 30, 2025 and December 31, 2024, aggregate liquidation preference of $650 at September 30, 2025 and December 31, 2024	650		650
Common stock; $0.01 par value; 500,000,000 shares authorized; 199,704,187 and 205,064,058 shares issued and 192,255,304 and 198,604,003 shares outstanding at September 30, 2025 and December 31, 2024, respectively	2		2
Additional paid-in-capital	166		705
Retained earnings	2,002		1,535
Treasury stock, at cost; 7,448,883 shares and 6,460,055 shares at September 30, 2025 and December 31, 2024, respectively	(745)		(297)
Accumulated other comprehensive loss	(105)		(117)

Total Stockholders' Equity	1,970		2,478
Total Liabilities and Stockholders' Equity	$	23,971	$	24,022

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine months ended September 30,
(In millions)	2025		2024
Cash Flows from Operating Activities
Net Income	$	798	$	482


Adjustments to reconcile net income to cash provided by operating activities:
Depreciation of property, plant and equipment and amortization of customer relationships and other intangible assets	667		814
Amortization of capitalized contract costs	363		231
Accretion of asset retirement obligations	22		29
Provision for credit losses	201		228

Amortization of financing costs and debt discounts	24		32
Loss on debt extinguishment	10		260
Amortization of in-the-money contracts and emissions allowances	75		83
Amortization of unearned equity compensation	83		82
Net loss/(gain) on sale of assets and disposal of assets	7		(197)
Gain on proceeds from insurance recoveries for property, plant and equipment, net	(100)		—

Impairment losses	—		15
Changes in derivative instruments	447		268
Changes in current and deferred income taxes and liability for uncertain tax benefits	209		134
Changes in collateral deposits in support of risk management activities	76		(80)



Equity in and distributions from earnings of unconsolidated affiliates	(2)		(6)
Changes in other working capital	(1,090)		(1,021)
Cash provided by operating activities	$	1,790	$	1,354


Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets	$	(591)	$	(33)
Capital expenditures	(849)		(286)

Net purchases of emissions allowances	(6)		(16)


Proceeds from sales of assets	6		495
Proceeds from insurance recoveries for property, plant and equipment, net	100		3



Cash (used)/provided by investing activities	$	(1,340)	$	163



Cash Flows from Financing Activities

Payments of dividends to preferred and common stockholders	$	(326)	$	(322)
Equivalent shares purchased in lieu of tax withholdings	(86)		(45)
Payments for share repurchase activity and excise tax	(958)		(316)
Payment for settlement of capped call options(a)	(292)		—
Net receipts/(payments) from settlement of acquired derivatives that include financing elements	51		(2)

Proceeds from issuance of long-term debt	1,375		875
Payments of deferred financing costs	(55)		(13)
Repayments of long-term debt and finance leases	(249)		(960)
Payments for debt extinguishment costs	—		(258)



Proceeds from credit facilities	1,575		1,050
Repayments to credit facilities	(1,575)		(1,050)
Cash used by financing activities	$	(540)	$	(1,041)


Effect of exchange rate changes on cash and cash equivalents	2		1

Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(88)		477
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,173		649
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	1,085	$	1,126

(a)Includes $16 million of payments for shares received from the exercise of the Capped Call Options. For further discussion, see Note 9, Changes in Capital Structure

See accompanying notes to condensed consolidated financial statements.

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, 2024	$	650	$	2	$	705	$	1,535	$	(297)	$	(117)	$	2,478
Net income							750						750

Other comprehensive income											2		2


Share repurchases(a)									(322)				(322)
Retirement of treasury stock(c)					(179)				179				—
Equity-based awards activity, net(d)					(8)								(8)

Common stock dividends and dividend equivalents declared(e)							(90)						(90)


Series A Preferred Stock dividends(f)							(33)						(33)


Balance at March 31, 2025	$	650	$	2	$	518	$	2,162	$	(440)	$	(115)	$	2,777
Net loss							(104)						(104)
Other comprehensive income											14		14
Shares reissuance for ESPP					2				6				8
Share repurchases(a)									(282)				(282)
Retirement of treasury stock(c)					(178)				178				—
Equity-based awards activity, net(d)					(3)								(3)

Common stock dividends and dividend equivalents declared(e)							(88)						(88)
Capped Call Options(g)					(34)								(34)
Balance at June 30, 2025	$	650	$	2	$	305	$	1,970	$	(538)	$	(101)	$	2,288
Net income							152						152
Other comprehensive loss											(4)		(4)
Share repurchases(a)(b)									(359)				(359)
Retirement of treasury stock(c)					(126)				126				—
Equity-based awards activity, net(d)					13								13

Common stock dividends and dividend equivalents declared(e)							(87)						(87)
Series A Preferred Stock dividends(f)							(33)						(33)
Settlement of Capped Call Options(g)					287				(287)				—
Conversion of Convertible Senior Notes(h)					(313)				313				—
Balance at September 30, 2025	$	650	$	2	$	166	$	2,002	$	(745)	$	(105)	$	1,970

(a)Includes excise tax accrued of $4 million, $2 million and $2 million for the quarters ended September 30, June 30 and March 31, 2025, respectively

(b)Excludes $16 million of payments for shares received from the exercise of the Capped Call Options. For further discussion, see Note 9, Changes in Capital Structure

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

(d)Includes $(9) million, $(37) million and $(40) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended September 30, June 30 and March 31, 2025, respectively

(e)Dividends per common share were $0.44 for each of the quarters ended September 30, June 30 and March 31, 2025

(f)Semi-annual dividend per share of Series A Preferred Stock was $51.25 for the periods ended September 15 and March 15, 2025

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

(h)For further discussion of the Convertible Senior Notes, see Note 7, Long-term Debt and Finance Leases


(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(i)					117				(117)				—
Retirement of treasury stock(j)					(38)				38				—
Equity-based awards activity, net(k)					8								8

Common stock dividends and dividend equivalents declared(l)							(86)						(86)
Series A Preferred Stock dividends(m)							(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(n)									(91)				(91)
Retirement of treasury stock(j)					(38)				38				—
Equity-based awards activity, net(k)					16								16

Common stock dividends and dividend equivalents declared(l)							(87)						(87)





Capped Call Options(o)					(253)								(253)
Balance at June 30, 2024	$	650	$	3	$	3,229	$	1,863	$	(2,019)	$	(103)	$	3,623
Net loss							(767)						(767)
Other comprehensive loss											(2)		(2)

Share repurchases(n)									(231)				(231)
Retirement of treasury stock(j)					(100)				100				—
Equity-based awards activity, net(k)					16								16

Common stock dividends and dividend equivalents declared(l)							(86)						(86)



Series A Preferred Stock dividends(m)							(33)						(33)

Balance at September 30, 2024	$	650	$	3	$	3,145	$	977	$	(2,150)	$	(105)	$	2,520

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

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

(k)Includes $(10) million, $(12) million and $(23) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended September 30, June 30 and March 31, 2024, respectively

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

(m)Semi-annual dividend per share of Series A Preferred Stock was $51.25 for the period ended September 15 and March 15, 2024

(n)Includes excise tax accrued of $2 million and $1 million for the quarter ended September 30 and June 30, 2024, respectively

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

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Nature of Business and Basis of Presentation

General

NRG Energy, Inc., or NRG or the Company, is a leading energy and smart home company powering a brighter, smarter future. The Company provides gas, electricity, and smart home solutions to approximately 8 million residential customers (comprised of 6 million retail energy customers and 2 million smart home customers) in addition to large commercial and industrial, hyperscaler, and wholesale customers. Across the U.S. and Canada, NRG is redefining customers’ experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of September 30, 2025, the Company’s core power and natural gas business consists of approximately 12 GW of competitive power generation, primarily in Texas, and a natural gas portfolio that serves approximately 1,800 MMDth annually.

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, and (ii) 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 2024 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 balance sheets as of September 30, 2025, and the results of operations, comprehensive income, cash flows and stockholders' equity for the three and nine months ended September 30, 2025 and 2024.

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.

Note 2 — Summary of Significant Accounting Policies

Depreciation and Amortization

The Company's depreciation and amortization included in the condensed consolidated statement of operations consisted of the following:


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2025		2024		2025		2024
Amortization of capitalized contract costs related to fulfillment	$	57	$	34	$	146	$	82
Amortization of capitalized contract costs related to customer acquisition	80		57		217		149
Amortization of customer relationships and other intangible assets	152		192		460		610
Depreciation of property, plant and equipment	71		69		207		204
Total depreciation and amortization	$	360	$	352	$	1,030	$	1,045

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 nine months ended September 30, 2025 and 2024:


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2025		2024		2025		2024
Beginning balance	$	127	$	127	$	152	$	145

Provision for credit losses	88		95		201		228
Write-offs	(69)		(74)		(239)		(252)
Recoveries collected	12		9		35		28
Other	6		7		15		15
Ending balance	$	164	$	164	$	164	$	164

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)	September 30, 2025		December 31, 2024
Property, plant and equipment accumulated depreciation	$	1,702	$	1,508
Customer relationships and other intangible assets accumulated amortization	3,822		3,632

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)	September 30, 2025		December 31, 2024
Cash and cash equivalents	$	732	$	966
Funds deposited by counterparties	323		199
Restricted cash	30		8
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,085	$	1,173

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 by the Company for projects under construction or that are restricted due to contractual or legal obligations.

Recent Accounting Developments — Guidance Not Yet Adopted

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. The Company is adopting the new guidance for the annual period ending December 31, 2025. ASU 2023-09 amends disclosure requirements only and will not have an impact on the Company’s results of operations, cash flows, or statement of financial position.

ASU 2024-03 – In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses, or ASU 2024-03. The guidance in ASU 2024-03 requires more detailed information about specified categories of expenses included in certain captions presented on the face of the income statement. This ASU is effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either (1) prospectively to financial statements issued for reporting periods after the effective date of this ASU or (2) retrospectively to all prior periods presented in the financial statements. The Company is currently evaluating the impact of adopting ASU 2024-03 on its disclosures.

ASU 2024-04 – In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20) – Induced Conversions of Convertible Debt Instruments, or ASU 2024-04. The guidance in ASU 2024-04 clarifies the requirements related to accounting for the settlement of a debt instrument as an induced conversion when changes are made to conversion features as part of an offer to settle the instrument. This ASU is effective for annual periods beginning after December 15, 2025, with early adoption permitted. The amendments may be applied either (1) prospectively to any settlements of convertible debt instruments that occur after the effective date of this ASU or (2) retrospectively to all prior periods presented in the financial statements, with a cumulative adjustment-effect adjustment to equity. The Company is currently evaluating the impact of adopting ASU 2024-04 on its disclosures.

ASU 2025-05 – In July 2025, the FASB issued ASU No. 2025-05, Financial Instruments—Credit Losses (Topic 326) – Measurement of Credit Losses for Accounts Receivable and Contract Assets, or ASU 2025-05. The amendment provides a practical expedient that allows entities to assume that current conditions as of the balance sheet date do not change for the remaining life of the asset when estimating expected credit losses for current accounts receivable and current contract assets. The amendments of ASU 2025-05 should be applied prospectively and are effective for annual and interim periods beginning after December 15, 2025, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU 2025-05 on its consolidated financial statements and related disclosures.

ASU 2025-06 – In September 2025, the FASB issued ASU No. 2025-06, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40)—Targeted Improvements to the Accounting for Internal-Use Software, or ASU 2025-06. The update amends guidance on capitalization of internal-use software development costs by removing the previous “development stage” model and clarifying the criteria that must be met for entities to begin capitalizing software costs. This ASU is effective for annual and interim periods beginning after December 15, 2027, with early adoption permitted. The amendments may be applied either (1) prospectively to financial statements issued for reporting periods after the effective date of this ASU, (2) retrospectively to all prior periods presented in the financial statement, or (3) using a modified transition approach based on whether an existing project can be capitalized under the updated guidance. The Company is currently evaluating the impact of adopting ASU 2025-06 on its consolidated financial statements and related disclosures.

ASU 2025-07 — In September 2025, the FASB issued ASU No. 2025-07, Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606) — Derivative Scope Refinements and Scope Clarification for Share-Based Noncash Consideration from a Customer in a Revenue Contract, or ASU 2025-07. The update refines the scope of derivative accounting guidance by providing a scope exception for non-exchange traded contracts with payments based on the operations or activities of one of the parties to the contract. The update also clarifies accounting under Topic 606 for share-based noncash

consideration received from a customer. This ASU is effective for annual and interim periods beginning after December 15, 2026, with early adoption permitted. The amendments may be applied either (1) prospectively to financial statements issued for reporting periods after the effective date of this ASU or (2) using a modified retrospective basis with a cumulative adjustment-effect adjustment to equity. The Company is currently evaluating the impact of adopting ASU 2025-07 on its consolidated financial statements and related disclosures.

Note 3 — Revenue Recognition

Performance Obligations

As of September 30, 2025, estimated future fixed fee performance obligations are $453 million for the remaining three months of fiscal year 2025, and $1.6 billion, $1.3 billion, $871 million, $549 million and $249 million for the fiscal years 2026, 2027, 2028, 2029 and 2030, 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.

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three and nine months ended September 30, 2025 and 2024:


	Three months ended September 30, 2025
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home	$	2,265	$	600	$	235	$	532	$	(19)	$	3,613
Business	1,035		2,166		468		—		—		3,669
Total retail revenue(a)	3,300		2,766		703		532		(19)		7,282
Energy revenue(a)	16		132		—		—		—		148
Capacity revenue(a)	—		87		—		—		—		87
Mark-to-market for economic hedging activities(b)	—		28		6		—		—		34
Contract amortization	—		1		—		—		—		1
Other revenue(a)	63		16		6		—		(2)		83
Total revenue	3,379		3,030		715		532		(21)		7,635
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		1		34		—		—		35
Less: Realized and unrealized ASC 815 revenue	23		68		8		—		(2)		97
Total revenue from contracts with customers	$	3,356	$	2,961	$	673	$	532	$	(19)	$	7,503
(a) 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	—		16		—		—		(2)		14
Capacity revenue	—		16		—		—		—		16
Other revenue	23		(1)		2		—		—		24
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Three months ended September 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home	$	2,235	$	616	$	349	$	499	$	(4)	$	3,695
Business	996		1,852		411		—		—		3,259
Total retail revenue(a)	3,231		2,468		760		499		(4)		6,954
Energy revenue(a)	12		67		52		—		(3)		128
Capacity revenue(a)	—		40		8		—		(1)		47
Mark-to-market for economic hedging activities(b)	—		1		6		—		1		8
Contract amortization	—		(7)		(1)		—		—		(8)
Other revenue(a)	58		31		8		—		(3)		94
Total revenue	3,301		2,600		833		499		(10)		7,223
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		14		13		—		—		27
Less: Realized and unrealized ASC 815 revenue	19		33		18		—		(1)		69
Total revenue from contracts with customers	$	3,282	$	2,553	$	802	$	499	$	(9)	$	7,127
(a) 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	$	—	$	6	$	—	$	—	$	—	$	6
Energy revenue	—		9		12		—		(3)		18
Capacity revenue	—		17		—		—		—		17
Other revenue	19		—		—		—		1		20
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Nine months ended September 30, 2025
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home	$	5,624	$	1,862	$	962	$	1,530	$	(53)	$	9,925
Business	2,842		7,862		1,388		—		—		12,092
Total retail revenue(a)	8,466		9,724		2,350		1,530		(53)		22,017
Energy revenue(a)	38		354		101		—		(1)		492
Capacity revenue(a)	—		182		14		—		(1)		195
Mark-to-market for economic hedging activities(b)	—		12		6		—		—		18
Contract amortization	—		(4)		—		—		—		(4)
Other revenue(a)	157		76		18		—		(9)		242
Total revenue	8,661		10,344		2,489		1,530		(64)		22,960
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		38		92		—		—		130
Less: Realized and unrealized ASC 815 revenue	33		127		7		—		(2)		165
Total revenue from contracts with customers	$	8,628	$	10,179	$	2,390	$	1,530	$	(62)	$	22,665
(a) 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	$	—	$	27	$	—	$	—	$	—	$	27
Energy revenue	—		38		—		—		(2)		36
Capacity revenue	—		48		—		—		—		48
Other revenue	33		2		1		—		—		36
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Nine months ended September 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home	$	5,361	$	1,855	$	1,362	$	1,434	$	(12)	$	10,000
Business	2,740		6,402		1,385		—		—		10,527
Total retail revenue(a)	8,101		8,257		2,747		1,434		(12)		20,527
Energy revenue(a)	35		194		170		—		(9)		390
Capacity revenue(a)	—		120		16		—		(3)		133
Mark-to-market for economic hedging activities(b)	—		15		14		—		3		32
Contract amortization	—		(23)		(2)		—		—		(25)
Other revenue(a)	161		84		17		—		(8)		254
Total revenue	8,297		8,647		2,962		1,434		(29)		21,311
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		36		38		—		—		74
Less: Realized and unrealized ASC 815 revenue	29		165		60		—		(4)		250
Total revenue from contracts with customers	$	8,268	$	8,446	$	2,864	$	1,434	$	(25)	$	20,987
(a) 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	$	—	$	25	$	—	$	—	$	—	$	25
Energy revenue	—		67		50		—		(8)		109
Capacity revenue	—		58		—		—		—		58
Other revenue	29		—		(4)		—		1		26
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

Contract Balances

The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of September 30, 2025 and December 31, 2024:


(In millions)	September 30, 2025		December 31, 2024
Capitalized contract costs (included in Prepayments and other current assets and Other non-current assets)	$	1,644	$	1,220

Accounts receivable, net - Contracts with customers	3,244		3,393
Accounts receivable, net - Accounted for under topics other than ASC 606	86		90
Accounts receivable, net - Affiliate	2		5
Total accounts receivable, net	$	3,332	$	3,488

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,316	$	1,548
Deferred revenues(a)	1,652		1,573

(a)Deferred revenues from contracts with customers as of September 30, 2025 and December 31, 2024 were approximately $1.6 billion and $1.5 billion, respectively.

The revenue recognized from contracts with customers during the three months ended September 30, 2025 and 2024 relating to the deferred revenue balance at the beginning of each period was $307 million and $290 million, respectively. The revenue recognized from contracts with customers during the nine months ended September 30, 2025 and 2024 relating to the deferred revenue balance at the beginning of each period was $576 million and $511 million, respectively. The change in deferred revenue balances during the three and nine months ended September 30, 2025 and 2024 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.

Note 4 — Acquisitions and Dispositions

Acquisitions

Anticipated Acquisition of LSP Portfolio

On May 12, 2025, NRG entered into a definitive agreement with LS Power to acquire a power portfolio including 13 GW of natural gas-fired generation facilities and a commercial & industrial virtual power plant platform with 6 GW of capacity (the “C&I VPP”). The consideration will consist of 24.25 million shares of NRG common stock and $6.4 billion in cash, subject to working capital adjustments as set forth in the purchase agreement. As part of the transaction, NRG will also assume approximately $3.2 billion of debt. The Company expects to fund the cash portion of the consideration using a combination of newly-issued debt and cash on hand. The acquisition is expected to close in the first quarter of 2026, and is subject to the satisfaction or waiver of specified closing conditions, consents and regulatory approvals, including Hart-Scott-Rodino (“HSR”), FERC, DOJ, and the New York State Public Service Commission (“NYSPSC”). The definitive agreement also provides that, upon termination of the agreement under certain specified circumstances, NRG will be required to pay LS Power a termination fee of $400 million.

In connection with the anticipated acquisition of the LSP Portfolio, NRG entered into a commitment letter for a 364-day Senior Secured Bridge Facility (the “Bridge Facility”) in a principal amount not to exceed $4.4 billion for the purposes of paying a portion of the cash consideration for the anticipated acquisition and paying fees and expenses in connection with the acquisition. The Bridge Facility was terminated on October 8, 2025 following the issuance of the New Unsecured Notes and the New Secured Notes (as defined in Note 7, Long-term Debt and Finance Leases).

Acquisition costs of $2 million and $25 million for the three and nine months ended September 30, 2025, respectively, are included in acquisition-related transaction and integration costs in the Company’s consolidated statement of operations.

Acquisition of Texas Generation Portfolio

On April 10, 2025, the Company acquired all of the ownership interests of six power generation facilities from Rockland Capital, LLC, adding 738 MW of natural gas-fired assets in Texas to its portfolio for $560 million in cash consideration, less $2 million in working capital adjustments. The acquisition enhances NRG’s integrated supply strategy with critical peaking and baseload capacity in key load zones across Texas.

Acquisition costs of $5 million for the nine months ended September 30, 2025 are included in acquisition-related transaction and integration costs in the Company’s consolidated statement of operations.

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

The purchase price is provisionally allocated as follows:


	(In millions)
Property, plant and equipment	$	644
Derivative instruments - Current assets	6
Derivative instruments - Other assets	2
Derivative instruments - Current liabilities	(34)
Derivative instruments - Other liabilities	(57)
Other, including current and non-current working capital	(3)
Texas Generation Portfolio Purchase Price	$	558

Dispositions

Sale of Airtron

On September 16, 2024, the Company closed on the sale of its 100% ownership in the Airtron business unit. Proceeds of $500 million were reduced by working capital and other adjustments of $16 million, resulting in net proceeds of $484 million. The Company recorded a gain on the sale of $208 million within the West/Services/Other region of operations.

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:


	September 30, 2025				December 31, 2024
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value




Convertible Senior Notes(a)	$	—	$	—	$	232	$	509

Other long-term debt, including current portion	12,013		11,837		10,648		10,252
Total long-term debt, including current portion(b)	$	12,013	$	11,837	$	10,880	$	10,761

(a)The Company settled all of the outstanding Convertible Senior Notes as of July 8, 2025. For further discussion, see Note 7, Long-term Debt and Finance Leases

(b)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 and the Term Loan B are based on quoted market prices and are classified as Level 2 within the fair value hierarchy. The estimated fair values of the T.H. Wharton TEF loan and the Cedar Bayou 5 TEF loan are determined using discounted cash flow methodologies, and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion, as of September 30, 2025 and December 31, 2024:


	September 30, 2025				December 31, 2024
(In millions)	Level 2		Level 3		Level 2		Level 3
Convertible Senior Notes	$	—	$	—	$	509	$	—

Other long-term debt, including current portion	11,576		261		10,252		—
Total long-term debt, including current portion	$	11,576	$	261	$	10,761	$	—

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:


	September 30, 2025
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	30	$	—	$	30	$	—



Derivative assets:

Foreign exchange contracts	8		—		8		—
Commodity contracts(a)	2,762		423		2,075		264


Equity securities measured using net asset value practical expedient (classified within other non-current assets)	7
Total assets	$	2,807	$	423	$	2,113	$	264
Derivative liabilities:
Interest rate contracts	$	6	$	—	$	6	$	—
Foreign exchange contracts	2		—		2		—
Commodity contracts(a)	2,508		420		1,901		187
Consumer Financing Program	295		—		—		295
Total liabilities	$	2,811	$	420	$	1,909	$	482

(a)Excludes $644 million of derivative assets and $194 million of derivative liabilities that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities


	December 31, 2024
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	28	$	—	$	28	$	—


Derivative assets:
Interest rate contracts	9		—		9		—
Foreign exchange contracts	22		—		22		—
Commodity contracts(a)	3,368		528		2,645		195



Equity securities measured using net asset value practical expedient (classified within other non-current assets)	6
Total assets	$	3,433	$	528	$	2,704	$	195
Derivative liabilities:
Interest rate contracts	$	3	$	—	$	3	$	—
Foreign exchange contracts	1		—		1		—
Commodity contracts(a)	2,970		432		2,382		156
Consumer Financing Program	203		—		—		203
Total liabilities	$	3,177	$	432	$	2,386	$	359

(a)Excludes $997 million of derivative assets and $227 million of derivative liabilities that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities

The following table reconciles, for the three and nine months ended September 30, 2025 and 2024, 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 September 30, 2025		Three months ended September 30, 2024		Nine months ended September 30, 2025		Nine months ended September 30, 2024
Beginning balance	$	81	$	121	$	39	$	119
Contracts added from Texas Generation Portfolio acquisition	—		—		(91)		—
Total gains/(losses) realized/unrealized included in earnings	11		(83)		45		(120)
Purchases	15		(38)		52		(7)
Transfers into Level 3(b)	(30)		(19)		33		(2)
Transfers out of Level 3(b)	—		(7)		(1)		(16)
Ending balance	$	77	$	(26)	$	77	$	(26)
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	$	3	$	(41)	$	50	$	(70)

(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, including volatilities, 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.

The following table reconciles, for the three and nine months ended September 30, 2025 and 2024, 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 September 30, 2025		Three months ended September 30, 2024		Nine months ended September 30, 2025		Nine months ended September 30, 2024
Beginning balance	$	(257)	$	(151)	$	(203)	$	(134)

New contractual obligations	(64)		(63)		(177)		(121)
Settlements	24		21		91		64
Total gains/(losses) included in earnings	2		(7)		(6)		(9)
Ending balance	$	(295)	$	(200)	$	(295)	$	(200)

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

Derivative Fair Value Measurements

The fair value of the Company’s contracts primarily consist of non-exchange traded contracts based on consensus pricing provided by independent pricing services. As of September 30, 2025, contracts valued with prices provided by models and other valuation techniques made up 10% of derivative assets and 17% 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, certain power options 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. Power options are valued using industry standard option models. The valuation of certain power options includes significant unobservable inputs such as forward volatilities. 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.

The following tables quantify the significant, unobservable inputs used in developing the fair value of the Company's Level 3 positions as of September 30, 2025 and December 31, 2024:



	September 30, 2025
	Fair Value						Input/Range
(In millions, except as noted)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	$	24	$	7	Discounted Cash Flow	Forward Market Price ($ per MMBtu)	$	0		$	15		$	5
Power Contracts	122		60		Discounted Cash Flow	Forward Market Price ($ per MWh)	0			126			32
Capacity Contracts	29		9		Discounted Cash Flow	Forward Market Price ($ per MW/Day)	40			534			234
RECs	12		16		Discounted Cash Flow	Forward Market Price ($ per Certificate)	2			385			18
FTRs	21		11		Discounted Cash Flow	Auction Prices ($ per MWh)	(57)			28,331			0
Power Options	56		84		Option Models	Volatilities	22		%	264		%	105		%
Consumer Financing Program	—		295		Discounted Cash Flow	Collateral Default Rates	0.71		%	41.10		%	7.81		%
					Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.54		%
					Discounted Cash Flow	Credit Loss Rates	6.40		%	60.00		%	16.19		%
	$	264	$	482



	December 31, 2024
	Fair Value						Input/Range
(In millions, except as noted)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	$	56	$	15	Discounted Cash Flow	Forward Market Price ($ per MMBtu)	$	2		$	27		$	4
Power Contracts	57		86		Discounted Cash Flow	Forward Market Price ($ per MWh)	0			109			39
Capacity Contracts	34		13		Discounted Cash Flow	Forward Market Price ($ per MW/Day)	16			510			220
RECs	30		14		Discounted Cash Flow	Forward Market Price ($ per Certificate)	2			375			15
FTRs	18		28		Discounted Cash Flow	Auction Prices ($ per MWh)	(50)			16,180			0
Consumer Financing Program	—		203		Discounted Cash Flow	Collateral Default Rates	0.52		%	76.80		%	11.71		%
					Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.83		%
					Discounted Cash Flow	Credit Loss Rates	6.00		%	60.00		%	14.22		%
	$	195	$	359

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant, unobservable inputs as of September 30, 2025 and December 31, 2024:

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)

Volatilities

Buy

Increase/(Decrease)

Higher/(Lower)

Volatilities

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 September 30, 2025, the credit reserve resulted in a $1 million increase in fair value, primarily within cost of operations. As of December 31, 2024, the credit reserve resulted in a $1 million decrease in fair value, 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 2024 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 2024 Form 10-K. As of September 30, 2025, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $1.5 billion and NRG held collateral (cash and letters of credit) against those positions of $278 million, resulting in a Net Exposure of $1.2 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 45% of the Company's exposure before collateral is expected to roll off by the end of 2026. 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	67	%
Financial institutions	33

Total as of September 30, 2025	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	73	%
Non-investment grade/Non-Rated	27
Total as of September 30, 2025	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 had no exposure to wholesale counterparties in excess of 10% of total Net Exposure as of September 30, 2025. 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 September 30, 2025, aggregate credit risk exposure managed by NRG to these counterparties was approximately $851 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 September 30, 2025, 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 September 30, 2025, 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 2037 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

On October 1, 2024, the Company elected NPNS for certain existing derivative contracts. Upon election of NPNS, the Company discontinued derivative accounting treatment and will no longer remeasure the derivative contracts at fair value each reporting period. The fair values of these derivative contracts were frozen as of October 1, 2024 and the Company is derecognizing the fair values to earnings at the same time as the contracts mature. The values of these contracts are included in Derivative instruments captions in the Consolidated Balance Sheets. Subsequent to the election date, costs associated with these contracts will be recorded when the underlying physical transaction is delivered. These derivative contracts extend through 2036.

Interest Rate Derivatives

NRG is exposed to changes in interest rates through the Company's issuance of debt. To mitigate the Company's interest rate risk, NRG enters into interest rate derivatives, including swaps and treasury locks. As of September 30, 2025, the Company had $700 million of interest rate swaps extending through 2029 to mitigate the risk of the floating rate of the Term Loan B. In July 2025, the Company entered into treasury locks with a total notional amount of $1.4 billion which were fully terminated in September 2025.

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 September 30, 2025, NRG had foreign exchange contracts extending through 2029. The Company marks these derivatives to market through the consolidated statement of operations.

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 customer. 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 customer; and

• Vivint Smart Home pays transactional fees associated with customer 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 September 30, 2025 and December 31, 2024. 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	September 30, 2025	December 31, 2024
Emissions	Short Ton	1	1
Renewable Energy Certificates	Certificates	11	13
Coal	Short Ton	8	10
Natural Gas	MMBtu	789	861

Power	MWh	90	91
Interest	Dollars	700	700
Foreign Exchange	Dollars	425	410
Consumer Financing Program	Dollars	1,443	1,219

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)	September 30, 2025		December 31, 2024		September 30, 2025		December 31, 2024




Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts - current	$	—	$	—	$	3	$	3
Interest rate contracts - long-term	—		9		3		—
Foreign exchange contracts - current	6		15		1		—
Foreign exchange contracts - long-term	2		7		1		1
Commodity contracts - current	1,716		2,295		1,618		2,067
Commodity contracts - long-term	1,046		1,073		890		903
Consumer Financing Program - current	—		—		169		137
Consumer Financing Program - long-term	—		—		126		66
Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	2,770	$	3,399	$	2,811	$	3,177
Deferred gains/losses on NPNS contracts - current	206		376		89		90
Deferred gains/losses on NPNS contracts - long-term	438		621		105		137
Deferred gains/losses on NPNS contracts(a)	$	644	$	997	$	194	$	227
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	3,414	$	4,396	$	3,005	$	3,404

(a)Balances related to certain derivative contracts that were previously accounted for as derivative contracts prior to the election of the NPNS exemption and the discontinuance of derivative accounting treatment as of the election date

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 September 30, 2025
Interest rate contracts:

Derivative liabilities	$	(6)	$	—	$	—	$	(6)

Foreign exchange contracts:
Derivative assets	$	8	$	(2)	$	—	$	6
Derivative liabilities	(2)		2		—		—
Total foreign exchange contracts	$	6	$	—	$	—	$	6
Commodity contracts:
Derivative assets	$	3,406	$	(2,498)	$	(278)	$	630
Derivative liabilities	(2,702)		2,498		42		(162)
Total commodity contracts	$	704	$	—	$	(236)	$	468
Consumer Financing Program:
Derivative liabilities	$	(295)	$	—	$	—	$	(295)
Total derivative instruments	$	409	$	—	$	(236)	$	173


	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, 2024
Interest rate contracts:
Derivative assets	$	9	$	(3)	$	—	$	6
Derivative liabilities	(3)		3		—		—
Total interest rate contracts	$	6	$	—	$	—	$	6
Foreign exchange contracts:
Derivative assets	$	22	$	(1)	$	—	$	21
Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	$	21	$	—	$	—	$	21
Commodity contracts:
Derivative assets	$	4,365	$	(2,992)	$	(168)	$	1,205
Derivative liabilities	(3,197)		2,992		61		(144)
Total commodity contracts	$	1,168	$	—	$	(107)	$	1,061
Consumer Financing Program:
Derivative liabilities	$	(203)	$	—	$	—	$	(203)


Total derivative instruments	$	992	$	—	$	(107)	$	885

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 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 September 30,				Nine months ended September 30,
Unrealized mark-to-market results	2025		2024		2025		2024
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)	$	(354)	$	(414)	$	(452)	$	39
Reversal of acquired loss/(gain) positions related to economic hedges	16		(8)		21		(3)
Net unrealized (losses)/gains on open positions related to economic hedges	(38)		(1,208)		103		(319)
Total unrealized mark-to-market losses for economic hedging activities	(376)		(1,630)		(328)		(283)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	—		(1)		2		(1)

Net unrealized (losses)/gains on open positions related to trading activity	(3)		(4)		5		1
Total unrealized mark-to-market (losses)/gains for trading activity	(3)		(5)		7		—
Total unrealized losses - commodities and foreign exchange	$	(379)	$	(1,635)	$	(321)	$	(283)

(a)For the three and nine months ended September 30, 2025, includes $(266) million and $(319) million, respectively, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2025		2024		2025		2024
Total impact to statement of operations - interest rate contracts	$	1	$	(49)	$	(13)	$	(31)
Unrealized gains included in revenues - commodities	$	31	$	3	$	25	$	32
Unrealized losses included in cost of operations - commodities	(416)		(1,633)		(332)		(321)
Unrealized gains/(losses) included in cost of operations - foreign exchange	6		(5)		(14)		6
Total impact to statement of operations - commodities and foreign exchange	$	(379)	$	(1,635)	$	(321)	$	(283)
Total impact to statement of operations - Consumer Financing Program	$	2	$	(7)	$	(6)	$	(9)

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

For the nine months ended September 30, 2025, the $103 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 nine months ended September 30, 2024, the $319 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 power prices.

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 were in a net liability position as of September 30, 2025 was $561 million. The Company is also party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, which was approximately $27 million as of September 30, 2025. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $19 million of additional collateral would be required for all contracts with credit rating contingent features as of September 30, 2025.

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

Note 7 — Long-term Debt and Finance Leases

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


(In millions, except rates)	September 30, 2025		December 31, 2024		Interest rate %
Recourse debt:
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 2029	798		798		5.750
Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	480		480		3.875
Senior Notes, due 2033	925		925		6.000
Senior Notes, due 2034	950		950		6.250
Convertible Senior Notes, due 2048	—		232		2.750

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 B, due 2031	2,305		1,317		SOFR + 1.750
Tax-exempt bonds	466		466		1.250 - 4.750
T.H. Wharton TEF loan, due 2045	177		—		3.000
Cedar Bayou 5 TEF loan, due 2045	200		—		3.000
Subtotal recourse debt	12,025		10,892





Finance leases	18		14		various
Subtotal long-term debt and finance leases (including current maturities)	12,043		10,906
Less current maturities	(777)		(996)
Less debt issuance costs	(99)		(86)
Discounts	(12)		(12)
Total long-term debt and finance leases	$	11,155	$	9,812

Recourse Debt

Issuance of Unsecured Notes and Secured Notes

On October 8, 2025, the Company issued $3.65 billion in aggregate principal amount of senior unsecured notes, consisting of (i) $1.25 billion aggregate principal amount of 5.750% senior notes due 2034 (the “2034 Notes”) and (ii) $2.4 billion aggregate principal amount of 6.000% senior notes due 2036 (the “2036 Notes” and, together with the 2034 Notes, the “New Unsecured Notes”). The New Unsecured Notes are senior unsecured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the term loans under the Senior Credit Facility. Interest on the 2034 Notes is paid semi-annually beginning on July 15, 2026 until the maturity date of January 15, 2034. Interest on the 2036 Notes is paid semi-annually beginning on July 15, 2026 until the maturity date of January 15, 2036.

On October 8, 2025, the Company also issued $1.25 billion in aggregate principal amount of senior secured first lien notes, consisting of (i) $625 million aggregate principal amount of 4.734% senior secured first lien notes due 2030 (the “2030 Notes”) and (ii) $625 million aggregate principal amount of 5.407% senior secured first lien notes due 2035 (the “2035 Notes” and, together with the 2030 Notes, the “New Secured Notes”). The New Secured Notes are senior secured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the term loans under the Senior Credit Facility. The New Secured Notes are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Senior Credit Facility, which collateral consists of a substantial portion of the property and assets owned by the Company and the guarantors. Interest on the 2030 Notes is paid semi-annually beginning on April 15, 2026 until the maturity date of October 15, 2030. Interest on the 2035 Notes is paid semi-annually beginning on April 15, 2026 until the maturity date of October 15, 2035.

The Company intends to use a portion of the net proceeds from the New Unsecured Notes and the New Secured Notes to partially fund the cash portion of the purchase price of the acquisition of the LSP Portfolio. In addition, the Company intends to use a portion of the net proceeds from the 2035 Notes to repay in full its $500 million aggregate principal amount of 2.000%

senior secured notes on the maturity date of December 2, 2025. If the anticipated acquisition of the LSP Portfolio is not consummated on or prior to November 13, 2026 or the Company terminates the purchase agreement relating to the anticipated acquisition of the LSP Portfolio, then the Company will be required to redeem all of the outstanding (1) New Unsecured Notes at a redemption price equal to 100% of the principal amount thereof, and (2) 2030 Notes at a redemption price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to, but not including, the redemption date.

Senior Secured Bridge Facility

In connection with the anticipated acquisition of the LSP Portfolio, the Company entered into a commitment letter for a senior secured bridge facility with certain financial institutions in a principal amount not to exceed $4.4 billion for the purposes of paying a portion of the cash consideration for the anticipated acquisition and related fees and expenses. The Bridge Facility was terminated on October 8, 2025 following the issuance of the New Unsecured Notes and the New Secured Notes.

Senior Credit Facility

Amendment to Term Loan

On July 22, 2025, the Company and APX Group LLC, as borrowers, and certain subsidiaries of the Company, as guarantors, entered into the Fifteenth Amendment to the Second Amended and Restated Credit Agreement (the “Fifteenth Amendment”) with, among others, Citicorp North America, Inc., as administrative agent and as collateral agent (the “Agent”), and certain financial institutions, as lenders, which amended the Company’s Second Amended and Restated Credit Agreement, dated as of June 30, 2016 (the “Credit Agreement”).

The Fifteenth Amendment amended the Credit Agreement by adding a new incremental Term Loan B in an aggregate principal amount of $1.0 billion (the “Incremental Term Loan B Facility” and the loans thereunder, the “Incremental Term Loans”), which Incremental Term Loan B Facility is fungible with the Company’s existing Term Loan B facility (the “Existing Term Loan B Facility”). The terms of the Incremental Term Loans are identical to those applicable to the Company’s Existing Term Loan B Facility.

At the Company’s election, the Incremental 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 Credit Agreement) plus 1.00%, in each case, plus a margin of 0.75%, or (2) Term SOFR (as defined in the Credit Agreement) (which will not be less than 0.00%) for a one-, three-, six-month or twelve-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 1.75%.

The Incremental Term Loan B Facility is guaranteed by each of the Company’s subsidiaries that guarantee the Company’s Revolving Credit Facility and Existing Term Loan B 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.

The Incremental Term Loan B Facility has a final maturity date of April 16, 2031 and amortizes at a rate of 1.00% per annum in equal quarterly installments (subject to any adjustments to such amortization payments to ensure that such Incremental Term Loan B Facility is fungible for U.S. federal tax purposes with the Company’s Existing Term Loan B Facility).

If an event of default occurs under the Incremental Term Loan B 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 Incremental Term Loan B 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 May 27, 2025, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Fourteenth Amendment to the Credit Agreement in order to (i) increase the commitments under the Revolving Credit Facility by $390 million (the “Incremental Commitments”) to an aggregate amount equal to $4.6 billion and (ii) make certain other amendments to the Credit Agreement. The terms of the Incremental Commitments (including pricing) are identical to those applicable to, and constitute the same class as the existing commitments under, the Revolving Credit Facility.

2048 Convertible Senior Notes

Convertible Senior Notes Redemption

On May 15, 2025, the Company issued a notice of redemption for the Convertible Senior Notes. On July 8, 2025 (the “Redemption Date”), the Company used cash on hand to redeem $12 million in aggregate principal amount of the Convertible Senior Notes, at a redemption price equal to 100.000%. The holders of the remaining outstanding Convertible Senior Notes elected to convert their Convertible Senior Notes prior to the Redemption Date and received $220 million in cash with respect to the remaining principal amount of the Convertible Senior Notes and a total of 3,986,335 shares for the conversion premium.

During the nine months ended September 30, 2024, the Company repurchased $343 million in aggregate principal of the Convertible Senior Notes using cash of $603 million, which resulted in a $260 million loss on debt extinguishment for the period.

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


	Three months ended September 30,						Nine months ended September 30,
(In millions, except percentages)	2025			2024			2025			2024
Contractual interest expense	$	—		$	1		$	3		$	7
Amortization of deferred finance costs	—			—			—			1
Total	$	—		$	1		$	3		$	8

Effective interest rate	0.00		%	0.76		%	1.62		%	2.31		%

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 in aggregate principal amount of the Convertible Senior Notes. In the second quarter of 2025, the expiration date of the options was extended from June 1, 2025 to July 8, 2025. The Capped Calls were exercised and settled on July 8, 2025 in connection with the redemption of the Convertible Senior Notes. For further discussion, see Note 9, Changes in Capital Structure.

Receivables Securitization Facilities

On June 20, 2025, NRG Receivables amended its existing Receivables Facility to extend the scheduled termination date to June 18, 2026.

Texas Development Priorities

On July 31, 2025, NRG THW GT LLC, a wholly-owned subsidiary of the Company, entered into a $216 million loan agreement with the PUCT under the TEF (the “First TEF loan”) to support the development of T.H. Wharton, which is currently under construction. The Company signed an Equity Contribution Agreement and Guaranty with respect to the First TEF Loan. The loan bears interest at a fixed rate of 3.000% per annum and has a final maturity date of July 31, 2045. As of October 31, 2025, $178 million of disbursements for the First TEF loan have occurred.

On September 26, 2025, NRG Cedar Bayou 5 LLC, a wholly-owned subsidiary of the Company, entered into a $562 million loan agreement with the PUCT under the TEF (the “Second TEF loan”) to support the development of Cedar Bayou 5, which is currently under construction. The Company signed an Equity Contribution Agreement and Guaranty with respect to the Second TEF Loan. The loan bears interest at a fixed rate of 3.000% per annum and has a final maturity date of September 26, 2045. As of October 31, 2025, $230 million of disbursements for the Second TEF loan have occurred.

Indian River Bonds

On October 23, 2025, the Company remarketed $57 million aggregate principal amount of NRG Indian River 2020 4.000% tax-exempt refinancing bonds due 2040 (the “IR 2040 Bonds”) and $190 million aggregate principal amount of NRG Indian River Power 2020 4.000% tax-exempt refinancing bonds due 2045 (the “IR 2045 Bonds”) (together the “IR Bonds”). The IR Bonds are guaranteed on a first priority basis by each of the Company's current and future subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The IR Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which consists of a substantial portion of the property and assets owned by the Company and the guarantors. The collateral securing the IR Bonds will, at the request of the Company, be released if the Company satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the IR Bonds or any of the Company's senior, unsecured debt securities or downgrade such ratings below investment grade. The IR Bonds were remarketed at a coupon of 4.000% and are subject to mandatory

tender and purchase on October 1, 2035 and have final maturity dates of October 1, 2040 for the IR 2040 Bonds and October 1, 2045 for the IR 2045 Bonds.

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, which has entered into financing transactions related to the Receivables Facility as further described in Note 12, Long-term Debt and Finance Leases, to the Company’s 2024 Form 10-K.

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


(In millions)	September 30, 2025		December 31, 2024
Accounts receivable, net and Other current assets	$	2,444	$	2,402




Current liabilities	154		155







Net assets	$	2,290	$	2,247

Note 9 — Changes in Capital Structure

As of September 30, 2025 and December 31, 2024, 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, 2024	650,000	205,064,058	(6,460,055)	198,604,003
Shares issued under LTIPs	—	1,668,474	—	1,668,474
Shares issued under ESPP	—	—	81,903	81,903

Shares repurchased	—	—	(7,874,491)	(7,874,491)
Settlements of Capped Call Options(a)	—	—	(4,211,054)	(4,211,054)
Conversions of Convertible Senior Notes	—	—	3,986,469	3,986,469
Retirement of treasury stock	—	(7,028,345)	7,028,345	—
Balance as of September 30, 2025	650,000	199,704,187	(7,448,883)	192,255,304
Shares issued under LTIPs	—	62,600	—	62,600
Shares issued under ESPP	—	—	94,004	94,004
Shares repurchased	—	—	(772,500)	(772,500)



Balance as of October 31, 2025	650,000	199,766,787	(8,127,379)	191,639,408

(a)Consists of partial settlement of 134 shares on June 2, 2025 and final settlement of 4,210,920 shares on July 8, 2025

Common Stock

Share Repurchases

The Company’s long-term capital allocation policy is to target allocating approximately 80% of cash available for allocation, after debt reduction, to be returned to shareholders. The Company is actively repurchasing shares under its existing $3.7 billion share repurchase program, which began in 2023. On October 16, 2025, the Board of Directors authorized an additional share repurchase program of up to $3.0 billion, to be executed through 2028.

The following table summarizes the share repurchases made under the $3.7 billion authorization through October 31, 2025:


	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	(a)		950
Total Share Repurchases during 2023	22,730,940			$	1,150	(b)
2024 Repurchases:
Repurchases made under the accelerated share repurchase agreements	1,163,230	(a)		—
Open market repurchases	10,562,333	$	87.57	925
Total Share Repurchases during 2024	11,725,563			$	925	(c)
2025 Repurchases:
Open market repurchases(d)	7,874,491	$	121.22	955
Shares received from the exercise of the Capped Call Options	224,585	$	69.38	16
Total Share Repurchases during the nine months ended September 30, 2025	8,099,076			$	971	(e)
Open market repurchases October 1, 2025 through October 31, 2025	772,500	$	167.41	129
Total Share Repurchases under the $3.7 billion authorization	43,328,079	$	73.26	$	3,175

(a)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

(b)Excludes $10 million of excise tax accrued in 2023 which was paid in 2024

(c)Excludes $9 million of excise tax accrued in 2024 which was paid in 2025

(d)Includes $6 million accrued as of September 30, 2025

(e)Excludes $8 million accrued for estimated excise tax for the nine months ended September 30, 2025

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 100% (between 1% and 10% prior to July 30, 2025), subject to an annual maximum of $25,000, 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 2025, NRG increased the annual dividend to $1.76 from $1.63 per share. A quarterly dividend of $0.44 per share was paid on the Company's common stock during the three months ended September 30, 2025. On October 20, 2025, NRG declared a quarterly dividend on the Company's common stock of $0.44 per share, payable on November 17, 2025 to stockholders of record as of November 3, 2025. Beginning in the first quarter of 2026, NRG will increase the annual dividend by 8% to $1.90 per share. The Company targets an annual dividend growth rate of 7%-9% per share in subsequent years.

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

Retirement of Treasury Stock

During the nine months ended September 30, 2025 and 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)
2025 Retirements:
Shares retired during the first quarter of 2025	3,070,996	$	58.23	$	179
Shares retired during the second quarter of 2025	2,443,610	73.01		178
Shares retired during the third quarter of 2025	1,513,739	83.45		126
Total shares retired during the nine months ended September 30, 2025	7,028,345			$	483
2024 Retirements:
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
Shares retired during the third quarter of 2024	2,833,382	35.40		100
Total shares retired during the nine months ended September 30, 2024	5,111,012			$	176

Capped Call Options

During the second quarter of 2024, the Company entered into Capped Calls to mitigate the impact of potential dilution. Each had a strike price of $40.63 per share, subject to certain adjustments, which correspond to the conversion price of the Convertible Senior Notes as of September 30, 2025. The Capped Calls had a cap price of $249.00 per share, subject to certain adjustments, and effectively locked in a conversion premium of $257 million on the remaining $232 million balance of the Convertible Senior Notes. The Capped Calls were separate transactions and not part of the terms of the Convertible Senior Notes. As these transactions met certain accounting criteria, the Capped Calls were recorded in stockholders' equity. In the second quarter of 2024, the Company recorded $253 million as a reduction to additional paid-in capital and a $4 million loss 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. In the second quarter of 2025, the expiration date of the options was extended from June 1, 2025 to July 8, 2025.

Upon the exercise and settlement of the Capped Calls on July 8, 2025, the Company paid a total amount of $292 million, inclusive of the initial conversion premium of $257 million. The Company received 4,210,920 shares of common stock, of which 3,986,335 were issued to the holders of the Convertible Senior Notes upon conversion, and the remaining 224,585 received were retired by the Company.

Preferred Stock

Series A Preferred Stock Dividends

During the quarters ended September 30 and March 31, 2025, the Company declared and paid semi-annual 10.25% dividends of $51.25 per share on its outstanding Series A Preferred Stock, each 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 relative 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. For the three and nine months ended September 30, 2024, the Convertible Senior Notes were convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock. The Company was including the potential share settlements, if any, in the denominator for purposes of computing diluted income/(loss) per share under the if converted method for periods when there was net income. The potential shares settlements were calculated as the excess of the Company's conversion obligation over the aggregate principal amount (which was settled in cash), divided by the average share price for the period. For the three and nine months ended September 30, 2025, the Company included the potential share settlements in the diluted income per share calculation for the period prior to the redemption date of July 8, 2025.

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


	Three months ended September 30,				Nine months ended September 30,
(In millions, except per share data)	2025		2024		2025		2024
Basic income/(loss) per share:
Net income/(loss)	$	152	$	(767)	$	798	$	482
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		51		51
Net income/(loss) available for common stockholders	$	135	$	(784)	$	747	$	431
Weighted average number of common shares outstanding - basic	193		207		196		207
Income/(Loss) per weighted average common share — basic	$	0.70	$	(3.79)	$	3.81	$	2.08

Diluted income/(loss) per share:
Net income/(loss)	$	152	$	(767)	$	798	$	482
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		51		51
Net income/(loss) available for common stockholders	$	135	$	(784)	$	747	$	431
Weighted average number of common shares outstanding - basic	193		207		196		207
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	2		—		2		3
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	195		207		201		213
Income/(Loss) per weighted average common share — diluted	$	0.69	$	(3.79)	$	3.72	$	2.02

For the three months ended September 30, 2024, the Company had 5 million of outstanding equity compensation instruments and 3 million of potential share settlement of the Convertible Senior Notes that were not included in the computation of the Company’s diluted loss per share. For all other periods presented, the Company had an insignificant number of outstanding equity instruments that were anti-dilutive and were not included in the computation of the Company's diluted income per share.

Note 11 — Segment Reporting

The Company’s segment structure reflects how management makes financial decisions and allocates resources. The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus except for Vivint Smart Home operations which are reported within the Vivint Smart Home segment. Corporate represents the corporate business activities, and corporate shared services, to support the Company’s operating segments. Beginning in the fourth quarter of 2024, Corporate now includes interest expense related to its consolidated debt financing activities and income tax expense related to its consolidated U.S. federal, foreign and state income taxes conforming to the way the Company internally manages and monitors the business. Prior periods amounts have been recast for comparative purposes to reflect this change, which had no impact on the Company’s consolidated financial position, results of operations, and cash flows. 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 2024 Form 10-K.

NRG’s chief operating decision maker ("CODM"), its chief executive officer, uses more than one measure to evaluate the performance of its segments and allocate resources, including net income/(loss) and various non-GAAP financial measures such as adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA. Net income/(loss) and Adjusted EBITDA are used to review business performance and allocate resources as it provides a clearer view of segment profitability by focusing on operational performance. Additionally, operating expenses’ impact on each operating segment results are analyzed. On a monthly basis, Adjusted EBITDA is compared against the budget, latest forecast, and prior period.


	Three months ended September 30, 2025
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue(a)	$	3,379	$	3,030	$	715	$	532	$	—	$	(21)	$	7,635
Operating expenses	2,997		2,869		722		270		24		(21)		6,861
Depreciation and amortization	95		37		10		207		11		—		360

Total operating cost and expenses	3,092		2,906		732		477		35		(21)		7,221

Operating income/(loss)	287		124		(17)		55		(35)		—		414
Equity in earnings of unconsolidated affiliates	—		—		1		—		—		—		1

Other income, net	—		—		—		2		8		—		10

Interest expense	—		—		—		—		(187)		—		(187)
Income/(loss) before income taxes	287		124		(16)		57		(214)		—		238
Income tax expense	—		—		—		—		86		—		86
Net income/(loss)	$	287	$	124	$	(16)	$	57	$	(300)	$	—	$	152






(a) Inter-segment sales and inter-segment net derivative gains and losses included in revenues	$	4	$	—	$	2	$	15	$	—	$	—	$	21

Other segment information
Capital expenditures	$	203	$	4	$	2	$	6	$	39	$	—	$	254


	Three months ended September 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue(a)	$	3,301	$	2,600	$	833	$	499	$	—	$	(10)	$	7,223
Operating expenses	4,274		2,470		875		258		24		(10)		7,891
Depreciation and amortization	81		39		23		198		11		—		352

Total operating cost and expenses	4,355		2,509		898		456		35		(10)		8,243
Gain on sale of assets	—		—		208		—		—		—		208
Operating (loss)/income	(1,054)		91		143		43		(35)		—		(812)
Equity in earnings of unconsolidated affiliates	—		—		6		—		—		—		6
Other income, net	(1)		(1)		6		(6)		7		—		5

Interest expense	—		—		—		—		(213)		—		(213)
(Loss)/income before income taxes	(1,055)		90		155		37		(241)		—		(1,014)
Income tax benefit	—		—		—		—		(247)		—		(247)
Net (loss)/income	$	(1,055)	$	90	$	155	$	37	$	6	$	—	$	(767)
(a) Inter-segment sales and inter-segment net derivative gains and losses included in revenues	$	5	$	—	$	5	$	—	$	—	$	—	$	10

Other segment information
Capital expenditures	$	87	$	2	$	3	$	8	$	14	$	—	$	114



	Nine months ended September 30, 2025
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue(a)	$	8,661	$	10,344	$	2,489	$	1,530	$	—	$	(64)	$	22,960
Operating expenses	7,383		9,756		2,258		947		95		(64)		20,375
Depreciation and amortization	271		110		34		582		33		—		1,030

Total operating cost and expenses	7,654		9,866		2,292		1,529		128		(64)		21,405
Loss on sale of assets	—		—		(7)		—		—		—		(7)
Operating income/(loss)	1,007		478		190		1		(128)		—		1,548
Equity in earnings of unconsolidated affiliates	—		—		4		—		—		—		4

Other income, net	(1)		4		(1)		(6)		30		—		26
Loss on debt extinguishment	—		—		—		—		(10)		—		(10)
Interest expense	—		—		—		—		(498)		—		(498)
Income/(loss) before income taxes	1,006		482		193		(5)		(606)		—		1,070
Income tax expense	—		—		—		—		272		—		272



Net income/(loss)	$	1,006	$	482	$	193	$	(5)	$	(878)	$	—	$	798
(a) Inter-segment sales and inter-segment net derivative gains and losses included in revenues	$	17	$	1	$	6	$	40	$	—	$	—	$	64

Other segment information
Capital expenditures	$	730	$	9	$	9	$	14	$	87	$	—	$	849



	Nine months ended September 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue(a)	$	8,297	$	8,647	$	2,962	$	1,434	$	—	$	(29)	$	21,311
Operating expenses	7,791		7,410		2,992		761		65		(29)		18,990
Depreciation and amortization	240		117		96		561		31		—		1,045
Impairment losses	—		—		15		—		—		—		15
Total operating cost and expenses	8,031		7,527		3,103		1,322		96		(29)		20,050
(Loss)/gain on sale of assets	(4)		—		213		—		—		—		209
Operating income/(loss)	262		1,120		72		112		(96)		—		1,470
Equity in earnings of unconsolidated affiliates	—		—		13		—		—		—		13

Other income, net	(1)		(1)		5		(10)		45		—		38
Loss on debt extinguishment	—		—		—		—		(260)		—		(260)
Interest expense	—		—		—		—		(528)		—		(528)
Income/(loss) before income taxes	261		1,119		90		102		(839)		—		733
Income tax expense	—		—		—		—		251		—		251



Net income/(loss)	$	261	$	1,119	$	90	$	102	$	(1,090)	$	—	$	482
(a) Inter-segment sales and inter-segment net derivative gains and losses included in revenues	$	15	$	—	$	14	$	—	$	—	$	—	$	29

Other segment information
Capital expenditures	$	212	$	2	$	13	$	18	$	41	$	—	$	286

The following table summarizes balance sheet information by segment:


	As of September 30, 2025
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Equity investments in affiliates	$	—	$	—	$	48	$	—	$	—	$	—	$	48
Goodwill	643		721		157		3,494		—		—		5,015
Total assets	9,545		8,965		2,622		6,667		16,714		(20,542)		23,971

	As of December 31, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Equity investments in affiliates	$	—	$	—	$	45	$	—	$	—	$	—	$	45
Goodwill	643		721		153		3,494		—		—		5,011
Total assets	6,925		8,021		2,254		6,624		15,543		(15,345)		24,022

Note 12 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:


	Three months ended September 30,						Nine months ended September 30,
(In millions, except rates)	2025			2024			2025			2024
Income/(Loss) before income taxes	$	238		$	(1,014)		$	1,070		$	733
Income tax expense/(benefit)	86			(247)			272			251

Effective income tax rate	36.1		%	24.4		%	25.4		%	34.2		%

For the three months ended September 30, 2025, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense. For the nine months ended September 30, 2025, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense, partially offset with favorable permanent differences.

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

On July 4, 2025, H.R.1 - One Big Beautiful Bill Act (“OBBB”) was enacted into law. The OBBB includes changes to U.S. tax law that will be applicable to NRG beginning in 2025. The impact of the OBBB on the Company’s condensed consolidated financial statements has been reflected in its third quarter current and deferred taxes, however, there is no material impact to the income tax expense for the three and nine months ended September 30, 2025.

On September 12, 2024, Treasury and the IRS released proposed regulations that provide guidance on the application of the CAMT. The proposed regulations allow the exclusion of unrealized mark-to-market gains and losses, related to qualified hedge transactions, from adjusted financial statement income. The Company will continue to evaluate the applicable corporation status and the impact of the CAMT based on the proposed regulations and new guidance. NRG as an applicable corporation is subject to the CAMT, however, there is no impact on the Company’s provision for income taxes from the CAMT for the three and nine months ended September 30, 2025 and 2024.

Uncertain Tax Benefits

As of September 30, 2025, NRG had a non-current tax liability of $62 million for uncertain tax benefits from positions taken on various federal, state, and foreign income tax returns inclusive of accrued interest. For the nine months ended September 30, 2025, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of September 30, 2025, NRG had cumulative interest and penalties related to these uncertain tax benefits of $5 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 2021. 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 September 30,				Nine months ended September 30,
(In millions)	2025		2024		2025		2024
Revenues from Related Parties Included in Revenue
Gladstone	$	1	$	1	$	2	$	2

Ivanpah(a)	14		12		38		37
Midway-Sunset	2		1		4		3


Total	$	17	$	14	$	44	$	42

(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 September 30, 2025, all hedges under the first liens were at-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 believes it 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, 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”) and smart home companies 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, electricity or smart home solutions.

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 breached its contractual duty to set customer variable rates based on actual and estimated supply costs. 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 prevailed in its challenge to Mirkin's expert reports. The Court granted XOOM's motion to exclude both reports on damages. As a result, Mirkin has no method to establish damages for its class. The Court is considering whether class certification is still appropriate. Recently, this matter was moved to a new judge for further handling. A trial setting is not expected before 2026. 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 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 and the case was sent back to the trial court. The parties

conducted fact and expert discovery and Direct Energy submitted its motion for summary judgment in August 2024. The parties are waiting for a ruling from the Court on summary judgment and class certification.

Sales Practice Lawsuit

A Vivint Smart Home competitor 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 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 appealed. The Fourth Circuit Court of Appeals issued its opinion on July 22, 2025, upholding the trial court’s judgment. Following the decision, the Company increased the accrual for this matter to the amount of the judgment plus accrued interest. On September 5, 2025, the Company paid the $190 million judgment, plus $34 million of accrued interest, for a total payment of $224 million.

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. The Company did not believe the verdict was legally supported and pursued appellate remedies. During the second quarter of 2025, the parties entered into a settlement agreement and dismissed the matter and pending appeals.

Winter Storm Uri Lawsuits

The Company has been named in certain property damage and wrongful death claims that have been filed in connection with Winter Storm Uri in its capacity as a generator and a retail electric provider. 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 retail electric providers 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 plaintiffs challenged the ruling and the matters are stayed pending appeals by the various parties. 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 believes it has established an appropriate accrual pending potential regulatory action by San Diego Gas & Electric regarding the Company's Encina facility.

NYSPSC – Order to Show Cause — The NYSPSC issued an order referred to as the Retail Reset Order in December 2019 that limited the offers of ESCOs 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 ESCOs’ 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. Subsequently, the NYSPSC issued an order referred to as the Clarification Order on September 18, 2020 stating the Retail Reset Order applies only to prospective customer contracts. 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 following the effective date of the order. NRG responded to the notices in February 2024. On September 23, 2025, the NYSPSC issued a follow-up order repeating the above and related allegations, and also alleging separately that the NRG retail supplier responsible for selling natural gas to commercial and industrial customers had been improperly serving residential customers. The follow-up order directed NRG to show cause why consequences, ranging from sales monitoring, fines, refunds, debarment and/or eligibility revocation, should not be imposed for failure to comply with the Retail Reset Order and other Commission directives. The Company believes it has complied with the law and applicable orders and does not agree with the NYSPSC's assertions. The Company is in the initial stage of preparing a defense to this matter and has served discovery requests to support its position.

Note 16 — Environmental 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. In general, the electric generation industry has faced increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water use and discharge, and threatened and endangered species including several rules promulgated in 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. At the federal level, the President has issued several Executive Orders and the EPA has proposed rules that indicate that the current administration intends to relax or rescind some recently promulgated regulations, which will affect the outcome of the rulemakings and related legal challenges described below. 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. 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. 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 D.C. Circuit held oral arguments related to this rule in December 2024. On February 5, 2025, the DOJ filed a motion asking the court to hold proceedings in abeyance while the EPA evaluates the rule. The court granted the motion on February 19, 2025. On June 17, 2025, the EPA proposed to repeal all GHG emission standards for fossil fuel-fired power plants under Section 111 of the CAA. The EPA is proposing to conclude that GHG emissions from domestic fossil fuel-fired EGUs do not contribute to dangerous air pollution at a level sufficient to invoke the EPA’s authority under CAA Section 111. In addition to its primary proposal to repeal all GHG emission standards for the power sector promulgated in both 2015 and 2024, the EPA has included an alternative proposal to repeal only specific portions.

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 (a Federal Implementation Plan or “FIP”) 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 U.S. Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of Texas's and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. On March 25, 2025, the Fifth Circuit upheld the EPA’s disapproval of Texas’s and Louisiana’s state plans but did not address the FIP. On May 9, 2025, Texas and other parties petitioned the Fifth Circuit for a rehearing with the whole court. On June 5, 2023, the EPA promulgated the FIP. On June 27, 2024, the U.S. Supreme Court stayed the FIP in the 11 states where the rule had not already been stayed. On April 14, 2025, the D.C. Circuit granted the EPA’s request to hold the legal challenges in abeyance while the EPA revisits the rule. The Company cannot predict the outcome of the legal challenges to the various state disapprovals and the final rule promulgated on June 5, 2023.

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. On October 2, 2025, the EPA published an advance notice of proposed rulemaking (“ANPRM”) announcing plans to revise the Regional Haze Rule and seeking public input on streamlining the requirements.

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 had been 2027. On April 8, 2025, the President signed a Proclamation that creates a 2-year exemption for compliance beginning on July 8, 2027 and ending on July 8, 2029 for certain coal units including those owned by the Company. Twenty-three states have challenged this rule in the D.C. Circuit. On June 17, 2025, the EPA proposed to repeal the majority of the 2024 final rule amending the MATS rule. The outcome of this rulemaking is uncertain.

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 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 two plants that have coal-fired units in Texas. On May 9, 2024, the EPA promulgated a rule that again 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 were consolidated in the Eighth Circuit of the U.S. Court of Appeals. The outcome of the legal challenges is uncertain. On February 19, 2025, the DOJ filed a motion asking the court to hold proceedings in abeyance while the U.S. presidential administration evaluates the rule, which the court granted. On October 2, 2025, the EPA proposed to amend the ELG by extending deadlines that were part of the 2024 Rule, updating the transfer provisions to allow facilities to switch between compliance alternatives, and creating authority for alternative applicability dates. The EPA also is seeking comment on issues regarding a separate, future rulemaking on the underlying standards.

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 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 the outcome of the legal challenges is uncertain.

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;

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

•Results of operations; and

•Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, material cash requirements and commitments, and other obligations.

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 nine months ended September 30, 2025 and 2024. Also refer to NRG's 2024 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, is a leading energy and smart home company powering a brighter, smarter future. The Company provides gas, electricity, and smart home solutions to approximately 8 million residential customers (comprised of 6 million retail energy customers and 2 million smart home customers) in addition to large commercial and industrial, hyperscaler, and wholesale customers. Across the U.S. and Canada, NRG is redefining customer’s experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of September 30, 2025, the Company’s core power and natural gas business consists of approximately 12 GW of competitive power generation, primarily in Texas, and a natural gas portfolio that serves approximately 1,800 MMDth annually.

Strategy

NRG's strategy is to maximize shareholder 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 NRG's strategy and facilitates value creation across NRG's business.

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 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 2024 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.

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. Key provisions of the law took effect on 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 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 salespeople. While the law states that it does not impair existing contracts, the Maryland Public Service Commission has ruled that grandfathering of existing contracts will end as of December 31, 2025, and that suppliers must issue separate bills for their charges for all new and renewing contracts as of January 1, 2025. On October 1, 2024, Green Mountain Energy Company, NRG’s renewable electricity provider, along with a retail trade association to which NRG belongs, filed a lawsuit in federal court challenging the constitutionality of Senate Bill 1. On November 18, 2024, the trial court denied the plaintiffs' motion for a preliminary injunction. The plaintiffs, including Green Mountain, filed an appeal to this denial in the Fourth Circuit Court of Appeals and oral argument occurred on October 24, 2025.

Regional Regulatory Developments

NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments, see Item 1 — Note 15, Regulatory Matters, to the condensed consolidated financial statements.

ERCOT/PUCT

Public Utility Commission of Texas’s 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 adopted a reliability standard that became effective in September 2024.

In 2023, 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). In December 2024, the PUCT decided to shelve implementation of the PCM for the time being. 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. Both DRRS and a firming requirement are currently in the design phase with final rules yet to be adopted.

Texas Energy Fund — Through Senate Bill 2627, the Texas Legislature created the TEF, 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 TEF 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, 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. In January 2025, the PUCT began accepting applications for completion bonus grants, and NRG, through its subsidiaries, has filed applications for each of the three projects referenced above. The 89th Texas Legislature passed Senate Bill 2268, which separated the 10,000 MW collective cap on the ERCOT loan and grant programs resulting in a 10,000 MW cap for the loan program and a separate 10,000 MW cap for the completion bonus grant program.

On August 29, 2024, the PUCT approved an initial portfolio of projects to move into a due diligence process with its third-party administrator. T.H. Wharton was among the projects selected to move into due diligence. On December 12, 2024, the PUCT approved the Cedar Bayou 5 project to move into due diligence. On March 13, 2025, the PUCT approved the Greens Bayou 6 project to move into due diligence. Greens Bayou 6 is projected to become commercially operational in mid-2028.

On July 31, 2025, the Company entered into the First TEF loan to support the development of T.H. Wharton, which is currently under construction. Commercial operation of the 415 MW facility is expected mid-2026.

On September 26, 2025, the Company entered into the Second TEF loan to support the development of Cedar Bayou 5, which is currently under construction. Commercial operation of the 689 MW combined cycle facility is expected mid-2028.

Real-time Co-optimization of Energy and Ancillary Services (“RTC”) — ERCOT is progressing with a multi-year project to upgrade its 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 has commenced market trials for testing the RTC project which began in Spring 2025 and will continue through Fall 2025 with production to go-live on December 5, 2025.

Senate Bill 6 (“SB 6”) — On June 20, 2025, the Governor of Texas signed SB 6 into law, which includes various provisions that concern how both ERCOT, transmission and distribution utilities, and power generation companies plan for and serve large loads (defined as 75 MWs and above) in the ERCOT market. SB 6 requires load forecasting by requiring criteria for inclusion into the forecast and by requiring financial commitments upon a request for a large load customer seeking interconnection to begin engineering studies. In addition, SB 6 includes processes by which large loads should be required or incentivized to curtail their operations. At the same time, SB 6 establishes a PUCT regulatory procedure to minimize potential reliability and stranded-cost impacts that may be associated with new large load co-locations with power generators that were interconnected to ERCOT and operating as stand-alone generators as of September 1, 2025. Generators connected to the grid after this date are exempt from this procedure. Finally, SB 6 requires the PUCT to investigate revising the cost allocation and rate design that governs the ERCOT transmission system. PUCT rulemaking is in progress.

PJM

Capacity Market Litigation and Reforms — On September 27, 2024, various public interest organizations filed a complaint at FERC against PJM seeking changes to the treatment of RMRs in the capacity market. On November 18, 2024, various state consumer advocates filed a complaint at FERC against PJM seeking revisions to several aspects of PJM’s capacity market, including requiring resources previously subject to categorical exemptions to participate in capacity auctions, longer notice periods for deactivating generating resources, and several other changes. On December 9, 2024, PJM submitted a filing at FERC proposing various capacity market updates regarding the treatment of qualifying resources that are retained under RMR agreements as capacity, retention of a dual-fuel fired combustion turbine plant as the reference resource, and updates to the Non-Performance Charge based on the RTO Net CONE for the 2026/2027 and 2027/2028 Delivery Years. On February 14, 2025, FERC approved PJM’s filings. One party filed a request for rehearing, and on August 8, 2025, FERC issued an order on the rehearing request.

On December 13, 2024, PJM filed tariff changes to add provisions enabling a one-time reliability-based expansion of the eligibility criteria for PJM’s interconnection process intended to allow a limited number of additional resources to participate in an upcoming interconnection queue. On February 11, 2025, FERC approved PJM’s filing. Multiple parties filed requests for rehearing, and on July 28, 2025, FERC issued an order on the rehearing requests.

On December 20, 2024, PJM submitted tariff changes that propose to require all Existing Generation Capacity Resources to offer into the capacity auctions beginning with the 2026/2027 Delivery Year as well as certain enhancements to the Market Seller Offer Cap. On February 20, 2025, FERC approved PJM’s filing.

On December 30, 2024, Pennsylvania Governor Josh Shapiro and the Commonwealth of Pennsylvania filed a complaint at FERC alleging that PJM’s demand curve cap is unjust and unreasonable. The December 30, 2024 complaint was dismissed by FERC on April 21, 2025 in light of a joint stipulation filed by Pennsylvania Governor Shapiro and PJM on February 14, 2025. On February 20, 2025, PJM submitted proposed revisions to its tariff to establish a price cap and a price floor for the auctions for 2026/2027 and 2027/2028 delivery years. Two parties filed requests for rehearing, and on September 30, 2025, FERC issued an order on the rehearing requests.

Consumer Advocates Complaint — On April 14, 2025, various state consumer advocates filed a complaint with FERC asking FERC to reprice the 2025/2026 PJM capacity auction results. If FERC were to grant the request, the capacity prices for the 2025/2026 delivery year would be expected to change. The complaint is pending at FERC.

Indian River RMR Proceeding — On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4. PJM identified reliability violations resulting from the proposed deactivation of Unit 4. The Company filed a cost based RMR rate schedule at FERC. The Company reached settlement with a number of the intervening parties and the settlement agreement was filed. On January 16, 2025, FERC issued an order approving the settlement agreement. Indian River Unit 4 retired on February 23, 2025. On May 19, 2025, Maryland Office of People’s Counsel filed an appeal to the Fourth Circuit Court of Appeals of FERC’s denial on its request for rehearing. On August 22, 2025, NRG filed a motion to transfer venue. The appeal is pending.

Revisions to PJM Locational Deliverability Area ("LDA") Reliability Requirement — The Base Residual Auction ("BRA") 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 LDA Reliability Requirement in the Tariff. This would allow PJM to exclude certain resources from the calculation of the LDA 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 LDA 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. Those parties filed an appeal to the Court of Appeals for the D.C. Circuit on November 5, 2024. Multiple parties, including NRG, intervened in the appeal and filed an opening brief on July 21, 2025. The petitioners filed a reply brief on August 20, 2025, with oral argument expected to be scheduled by the end of 2025.

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 BRA 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 BRA and the rerun of the 2024/2025 BRA. As a result, the price of capacity for the 2024/2025 delivery year in the Delmarva Power and Light South zone was higher than originally published. This outcome may change depending upon the disposition of the outstanding complaint and appeals.

PJM Base Residual Auction Revisions and Delay — On October 13, 2023, PJM made two filings at FERC. In the first filing, PJM proposed revisions to the Market Seller Offer Cap, which FERC rejected on February 6, 2024. The second filing proposed to make changes to PJM’s resource adequacy risk modeling and capacity accreditation processes, which FERC approved, with condition, on January 20, 2024. The approved changes were in effect for the 2025/2026 BRA that occurred in July 2024. In November 2024, at PJM’s request, FERC approved delays to future BRAs.

On July 22, 2025, PJM announced the results of its BRA for the 2026/2027 planning year. The price came in at the FERC-approved cap of $329.17/MW-day for the entire PJM footprint of which NRG cleared approximately 1,008 MWs from the Company’s PJM generation fleet. NRG’s expected capacity revenues from the BRA for the 2026/2027 delivery year is approximately $121 million.

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 and regulatory 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. In general, the electric generation industry has faced increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water use and discharge, and threatened and endangered species including several rules promulgated in 2024. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose additional restrictions the operations of the Company's facilities including unit retirements or impose obligations related to historic coal ash use, storage and disposal. At the federal level, the President has issued several Executive Orders and the EPA has proposed rules that indicate that the current administration intends to relax or rescind some recently promulgated regulations, which will affect the outcome of the rulemakings and related legal challenges described below. 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.

Several 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, legal challenges and reconsiderations are resolved. The Company’s environmental matters are described in the Company’s 2024 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.

CSAPR — On March 15, 2023, the EPA signed and released a prepublication version of a FIP 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 U.S. Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of Texas's and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. On March 25, 2025, the Fifth Circuit upheld the EPA’s disapproval of Texas’s and Louisiana’s state plans but did not address the FIP. On May 9, 2025, Texas and other parties petitioned the Fifth Circuit for a rehearing with the whole court. On June 5, 2023, the EPA promulgated the FIP. On June 27, 2024, the U.S. Supreme Court stayed the FIP in the 11 states where the rule had not already been stayed. On April 14, 2025, the D.C. Circuit granted the EPA’s request to hold the legal challenges in abeyance while the EPA revisits the rule. The Company cannot predict the outcome of the legal challenges to the various state disapprovals and the final rule promulgated on June 5, 2023.

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, 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. On October 2, 2025, the EPA published an ANPRM announcing plans to revise the Regional Haze Rule and seeking public input on streamlining the requirements.

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 had been 2027. On April 8, 2025, the President signed a Proclamation that creates a 2-year exemption for compliance beginning on July 8, 2027 and ending on July 8, 2029 for certain coal units including those owned by the Company. Twenty three states have challenged this rule in the D.C. Circuit. On June 17, 2025, the EPA proposed to repeal the majority of the 2024 final rule amending the MATS rule. The outcome of this rulemaking is uncertain. The Company anticipates that the U.S. presidential administration will substantively revise this rule.

Water

The Company is required under the Clean Water Act 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.

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 were consolidated in the Eighth Circuit of the U.S. Court of Appeals. The outcome of the legal challenges is uncertain. On February 19, 2025, the DOJ filed a motion asking the court to hold proceedings in abeyance while the U.S. presidential administration evaluates the rule, which the court granted. On October 2, 2025, the EPA proposed to amend the ELG by extending deadlines that were part of the 2024 Rule, updating the transfer provisions to allow facilities to switch between compliance alternatives, and creating authority for alternative applicability dates. The EPA also is seeking comment on issues regarding a separate, future rulemaking on the underlying standards.

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 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) 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 the outcome of the legal challenges is uncertain. The Company anticipates that the U.S. presidential administration will revisit this rule.

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.

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.

Houston Nonattainment for 2008 Ozone Standard — In 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 2025 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:

Anticipated Acquisition of LSP Portfolio

On May 12, 2025, NRG entered into a definitive agreement with LS Power to acquire a power portfolio including 13 GW of natural gas-fired generation facilities and the C&I VPP platform with 6 GW of capacity. The consideration will consist of 24.25 million shares of NRG common stock and $6.4 billion in cash, subject to working capital adjustments as set forth in the purchase agreement. The Company intends to use a portion of the net proceeds from the New Unsecured Notes and the New Secured Notes to partially fund the cash portion of the purchase price of the acquisition of the LSP Portfolio. As part of the transaction, NRG will also assume approximately $3.2 billion of debt. The acquisition is expected to close in the first quarter of 2026, and is subject to the satisfaction or waiver of specified closing conditions, consents and regulatory approvals, including HSR, FERC, DOJ, and NYSPSC. For further discussion, see Note 4, Acquisitions and Dispositions.

Acquisition of Texas Generation Portfolio

On April 10, 2025, the Company acquired all of the ownership interests of six power generation facilities from Rockland Capital, LLC, adding 738 MW of natural gas-fired assets in Texas to its portfolio for $560 million in consideration, less $2 million in working capital adjustments. For further discussion, see Note 4, Acquisitions and Dispositions. The Company acquired the following generation facilities:

Name of Facility

Power Market

Plant Type

Primary Fuel

Location

Net Generation Capacity (MW)(a)

% Owned

Victoria

ERCOT

Fossil

Natural Gas

290

100.0

Victoria Port II

ERCOT

Fossil

Natural Gas

100.0

SJRR

ERCOT

Fossil

Natural Gas

100.0

Port Comfort

ERCOT

Fossil

Natural Gas

100.0

Chamon

ERCOT

Fossil

Natural Gas

100.0

Texas Gulf Sulphur (Wharton)

ERCOT

Fossil

Natural Gas

100.0

Total

738

(a) Capacity is an estimate as of the acquisition date and can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time

Capital Allocation

During the nine months ended September 30, 2025, the Company completed $971 million of share repurchases at an average price of $119.78 per share. Through October 31, 2025, an additional $129 million of share repurchases were executed at an average price of $167.41 per share. On October 16, 2025, the Board of Directors authorized an additional share repurchase program of up to $3.0 billion, to be executed through 2028. See Note 9, Changes in Capital Structure for additional discussion.

In the first quarter of 2025, NRG increased the annual common stock dividend to $1.76 from $1.63 per share, representing an 8% increase from 2024. Beginning in the first quarter of 2026, NRG will increase the annual dividend by 8% to $1.90 per share. The Company targets an annual dividend growth rate of 7-9% per share in subsequent years.

Issuance of Unsecured Notes and Secured Notes

On October 8, 2025, the Company issued $3.65 billion and $1.25 billion in aggregate principal amount of the New Unsecured Notes and New Secured Notes, respectively. The New Unsecured Notes are senior unsecured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the term loans under the Senior Credit Facility. The New Secured Notes are senior secured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the term loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Operations

In March 2025, the PUCT selected the Greens Bayou 6 project to advance to the next phase of due diligence, marking the third NRG project chosen under the TEF due diligence process. This project is expected to be operational in 2028.

On February 13, 2025, NRG signed a strategic Project Development Agreement with GE Vernova (“GEV”) and Kiewit’s subsidiary, TIC, to develop and construct up to 5.4 GW of new gas-fired, combined cycle generation projects. The generation facilities will be owned and operated by NRG. Additionally, NRG has entered into two slot reservation agreements with GEV for the procurement of 2.4 GW of 7HA gas turbines. The first projects under this comprehensive development agreement are expected to commence operations by the end of 2029.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2024 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:

Tariffs — NRG’s business is affected by various macroeconomic factors, including tariffs. The U.S. has implemented, or is considering implementing, higher tariffs on imports into the U.S. Any potential increases in capital and operational expenditures may impact the Company’s procurement and sourcing strategies.

Affordability — Rising customer bills, driven by rising regulated transmission and distribution charges along with load growth, have heightened customer and regulatory focus on energy affordability, including evolving discussions regarding market design and frameworks governing customer-sited generation. NRG is monitoring and seeking to address these developments through its customer-focused business strategy and public policy advocacy efforts.

Changes in Accounting Standards

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

Consolidated Results of Operations

The following table provides selected financial information for the Company:


	Three months ended September 30,						Nine months ended September 30,
(In millions)	2025		2024		Change		2025		2024		Change
Revenue
Retail revenue	$	7,282	$	6,954	$	328	$	22,017	$	20,527	$	1,490
Energy revenue(a)	148		128		20		492		390		102
Capacity revenue(a)	87		47		40		195		133		62
Mark-to-market for economic hedging activities	34		8		26		18		32		(14)
Contract amortization	1		(8)		9		(4)		(25)		21
Other revenues(a)(b)	83		94		(11)		242		254		(12)
Total revenue	7,635		7,223		412		22,960		21,311		1,649
Operating Costs and Expenses
Cost of fuel	343		296		(47)		928		648		(280)
Purchased energy and other cost of sales(c)	4,975		4,775		(200)		15,698		14,723		(975)

Mark-to-market for economic hedging activities	410		1,638		1,228		346		315		(31)
Contract and emissions credit amortization(c)	15		(3)		(18)		43		43		—
Operations and maintenance	396		401		5		1,118		1,192		74
Other cost of operations	102		132		30		298		308		10
Cost of operations (excluding depreciation and amortization shown below)	6,241		7,239		998		18,431		17,229		(1,202)
Depreciation and amortization	360		352		(8)		1,030		1,045		15
Impairment losses	—		—		—		—		15		15
Selling, general and administrative costs (excluding amortization of customer acquisition costs of $78, $55, $211 and $144, respectively, which are included in depreciation and amortization shown separately above)	612		645		33		1,885		1,739		(146)

Acquisition-related transaction and integration costs	8		7		(1)		59		22		(37)
Total operating costs and expenses	7,221		8,243		1,022		21,405		20,050		(1,355)

Gain/(loss) on sale of assets	—		208		(208)		(7)		209		(216)
Operating Income/(Loss)	414		(812)		1,226		1,548		1,470		78
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	1		6		(5)		4		13		(9)

Other income, net	10		5		5		26		38		(12)
Loss on debt extinguishment	—		—		—		(10)		(260)		250
Interest expense	(187)		(213)		26		(498)		(528)		30
Total other expense	(176)		(202)		26		(478)		(737)		259
Income/(Loss) Before Income Taxes	238		(1,014)		1,252		1,070		733		337
Income tax expense/(benefit)	86		(247)		(333)		272		251		(21)




Net Income/(Loss)	$	152	$	(767)	$	919	$	798	$	482	$	316

(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

Management’s discussion of the results of operations for the three months ended September 30, 2025 and 2024

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 September 30, 2025 and 2024:


	Average on Peak Power Price ($/MWh)
	Three months ended September 30,
Region	2025		2024		Change %
Texas
ERCOT - Houston(a)	$	38.68	$	34.12	13	%
ERCOT - North(a)	36.94		34.21		8	%

East
NY J/NYC(b)	$	66.57	$	44.09	51	%
NEPOOL(b)	62.77		45.87		37	%
COMED (PJM)(b)	55.33		38.03		45	%
PJM West Hub(b)	61.48		49.70		24	%

West
MISO - Louisiana Hub(b)	$	40.93	$	30.68	33	%
CAISO - SP15(b)	36.34		43.12		(16)	%

(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 September 30, 2025 and 2024:


	Three months ended September 30,
	2025		2024		Change %
($/MMBtu)	$	3.07	$	2.16	42	%

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 management. 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.

The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2025 and 2024:


	Three months ended September 30, 2025
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	3,300	$	2,766	$	703	$	532	$	(19)	$	7,282
Energy revenue	16		132		—		—		—		148
Capacity revenue	—		87		—		—		—		87
Mark-to-market for economic hedging activities	—		28		6		—		—		34
Contract amortization	—		1		—		—		—		1
Other revenue(a)	63		16		6		—		(2)		83
Total revenue	3,379		3,030		715		532		(21)		7,635
Cost of fuel	(274)		(60)		(9)		—		—		(343)
Purchased energy and other cost of sales(b)(c)(d)	(1,776)		(2,551)		(599)		(56)		7		(4,975)
Mark-to-market for economic hedging activities	(407)		37		(40)		—		—		(410)
Contract and emissions credit amortization	(7)		(5)		(3)		—		—		(15)
Depreciation and amortization	(95)		(37)		(10)		(207)		(11)		(360)
Gross margin	$	820	$	414	$	54	$	269	$	(25)	$	1,532
Less: Mark-to-market for economic hedging activities, net	(407)		65		(34)		—		—		(376)
Less: Contract and emissions credit amortization, net	(7)		(4)		(3)		—		—		(14)
Less: Depreciation and amortization	(95)		(37)		(10)		(207)		(11)		(360)
Economic gross margin	$	1,329	$	390	$	101	$	476	$	(14)	$	2,282
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $970 million, $56 million and $198 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)	12,462		4,175		621		—		—		17,258
Business electricity sales volume (GWh)	10,990		12,477		3,759		—		—		27,226
Home natural gas sales volume (MDth)	—		2,699		4,440		—		—		7,139
Business natural gas sales volume (MDth)	—		298,222		37,449		—		—		335,671
Average retail Home customer count (in thousands)(a)	2,873		2,125		713		—		—		5,711
Ending retail Home customer count (in thousands)(a)	2,844		2,115		714		—		—		5,673
Average Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,317		—		2,317
Ending Vivint Smart Home customer count (in thousands) (b)	—		—		—		2,351		—		2,351
Power generation
GWh sold	9,299		1,941		1		—		—		11,241
GWh generated(c)
Coal	6,287		1,249		—		—		—		7,536
Gas	3,012		3		—		—		—		3,015


Oil	—		8		—		—		—		8
Renewables	—		—		1		—		—		1
Total	9,299		1,260		1		—		—		10,560
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home includes customers that also purchase other NRG products
(c) Includes owned generation, excludes tolled generation and equity investments. Cottonwood was leased until May 2025


	Three months ended September 30, 2024
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	3,231	$	2,468	$	760	$	499	$	(4)	$	6,954
Energy revenue	12		67		52		—		(3)		128
Capacity revenue	—		40		8		—		(1)		47
Mark-to-market for economic hedging activities	—		1		6		—		1		8
Contract amortization	—		(7)		(1)		—		—		(8)
Other revenue(a)	58		31		8		—		(3)		94
Total revenue	3,301		2,600		833		499		(10)		7,223
Cost of fuel	(226)		(44)		(26)		—		—		(296)
Purchased energy and other cost of sales(b)(c)(d)	(1,996)		(2,122)		(625)		(37)		5		(4,775)
Mark-to-market for economic hedging activities	(1,537)		(10)		(90)		—		(1)		(1,638)
Contract and emissions credit amortization	(5)		11		(3)		—		—		3
Depreciation and amortization	(81)		(39)		(23)		$	(198)	(11)		(352)
Gross margin	$	(544)	$	396	$	66	$	264	$	(17)	$	165
Less: Mark-to-market for economic hedging activities, net	(1,537)		(9)		(84)		—		—		(1,630)
Less: Contract and emissions credit amortization, net	(5)		4		(4)		—		—		(5)
Less: Depreciation and amortization	(81)		(39)		(23)		(198)		(11)		(352)
Economic gross margin	$	1,079	$	440	$	177	$	462	$	(6)	$	2,152
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $960 million, $61 million and $203 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)	13,126		4,357		582		—		—		18,065
Business electricity sales volume (GWh)	11,196		12,583		1,973		—		—		25,752
Home natural gas sales volume (MDth)	—		3,464		4,985		—		—		8,449
Business natural gas sales volume (MDth)	—		312,871		36,617		—		—		349,488
Average retail Home customer count (in thousands)(a)	2,946		2,157		755		—		—		5,858
Ending retail Home customer count (in thousands)(a)	2,921		2,132		718		—		—		5,771
Average Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,137		—		2,137
Ending Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,154		—		2,154
Power generation
GWh sold	8,598		1,521		1,468		—		—		11,587
GWh generated(c)
Coal	5,417		1,040		—		—		—		6,457
Gas	3,181		1		1,467		—		—		4,649

Oil	—		1		—		—		—		1
Renewables	—		—		1		—		—		1
Total	8,598		1,042		1,468		—		—		11,108
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments

The following table represents the weather metrics for the three months ended September 30, 2025 and 2024:


	Three months ended September 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2025
CDDs(a)	1,659	773	1,123
HDDs(a)	—	33	3
2024
CDDs	1,714	814	1,194
HDDs	—	28	11
10-year average
CDDs	1,719	847	1,195
HDDs	5	45	9

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A 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 $1.4 billion and economic gross margin increased $130 million during the three months ended September 30, 2025, compared to the same period in 2024.

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

Texas


	(In millions)
Higher gross margin due to the following: •a 17%, or $194 million decrease in cost to serve the retail load, driven by lower realized power prices associated with the Company's diversified supply strategy •an increase in net revenue of $90 million, primarily driven by changes in customer term, product and mix	$	284
Lower gross margin primarily due to a decrease in load driven by changes in customer mix and attrition	(38)

Other	4
Increase in economic gross margin	$	250
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	1,130
Increase in contract and emissions credit amortization	(2)
Increase in depreciation and amortization	(14)
Increase in gross margin	$	1,364

East


	(In millions)
Lower gross margin due to the deactivation of Indian River Unit 4 in February 2025	$	(12)
Lower electric gross margin due to higher supply costs of $16.90 per MWh, or $286 million, driven primarily by increases in power prices, partially offset by higher net revenue rates of $11.70 per MWh, or $202 million as a result of changes in customer term, product, and mix	(84)
Lower electric gross margin from a decrease in load due to a change in customer mix and weather	(7)

Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in higher net revenue rates from changes in customer term, product, and mix of $0.60 per Dth, or $188 million, partially offset by higher supply costs of $0.55 per Dth, or $172 million, driven by an increase in gas costs	16
Lower natural gas gross margin from a decrease in load due to a change in customer mix	(7)

Higher gross margin due to a 145% increase in PJM capacity prices	27
Higher gross margin primarily due to an increase in average realized prices at Midwest Generation	10

Higher gross margin from demand response, primarily as a result of curtailment events during the third quarter of 2025	11
Other	(4)
Decrease in economic gross margin	$	(50)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	74
Increase in contract amortization	(8)
Decrease in depreciation and amortization	2
Increase in gross margin	$	18

West/Services/Other


	(In millions)
Lower gross margin due to the disposition of Services businesses	$	(38)
Lower natural gas gross margin due to higher supply costs of $0.20 per Dth, or $9 million, partially offset by higher net revenue rates of $0.10 per Dth, or $3 million	(6)
Higher electric gross margin due to lower supply costs of $12.00 per MWh, or $52 million and customer mix of $13 million, partially offset by lower net revenue rates of $11.00 per MWh, or $48 million	17
Higher gross margin primarily due to an increase in home protection plan sales	14

Lower gross margin at Cottonwood driven by the termination of the facility lease in May 2025	(62)

Other	(1)
Decrease in economic gross margin	$	(76)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	50
Decrease in contract amortization	1
Decrease in depreciation and amortization	13
Decrease in gross margin	$	(12)

Vivint Smart Home


	(In millions)
Higher gross margin primarily driven by growth in customers of $33 million and higher revenue rates of $0.58 per customer, or $4 million	$	37
Lower gross margin due to a decrease in non-recurring sales revenue	(13)
Lower gross margin due to an increase in personnel and related support costs	(6)
Other	(4)
Increase in economic gross margin	$	14


Increase in depreciation and amortization	(9)
Increase in gross margin	$	5

Mark-to-Market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results increased by $1.3 billion during the three months ended September 30, 2025, compared to the same period in 2024.

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


	Three months ended September 30, 2025
(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	$	—	$	—	$	8	$	—	$	8

Net unrealized gains/(losses) on open positions related to economic hedges	—		28		(2)		—		26
Total mark-to-market gains in revenue	$	—	$	28	$	6	$	—	$	34
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)	$	(361)	$	(31)	$	30	$	—	$	(362)
Reversal of acquired loss positions related to economic hedges	14		2		—		—		16
Net unrealized (losses)/gains on open positions related to economic hedges	(60)		66		(70)		—		(64)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(407)	$	37	$	(40)	$	—	$	(410)

(a)Includes $(266) million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities


	Three months ended September 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	$	—	$	4	$	9	$	1	$	14
Reversal of acquired (gain) positions related to economic hedges	—		(1)		—		—		(1)
Net unrealized (losses) on open positions related to economic hedges	—		(2)		(3)		—		(5)
Total mark-to-market gains in revenue	$	—	$	1	$	6	$	1	$	8
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(498)	$	96	$	(25)	$	(1)	$	(428)
Reversal of acquired (gain)/loss positions related to economic hedges	(9)		3		(1)		—		(7)
Net unrealized (losses) on open positions related to economic hedges	(1,030)		(109)		(64)		—		(1,203)
Total mark-to-market (losses) in operating costs and expenses	$	(1,537)	$	(10)	$	(90)	$	(1)	$	(1,638)

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.

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

For the three months ended September 30, 2025, the $34 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 prices and the reversal of previously recognized unrealized losses on contracts that settled during the period. The $410 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 and a decrease in the value of open positions in West as a result of decreases in CAISO power prices.

For the three months ended September 30, 2024, the $8 million gain in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $1.6 billion loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.

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 September 30, 2025 and 2024. 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 September 30,
(In millions)	2025		2024
Trading gains/(losses)
Realized	$	25	$	25
Unrealized	(3)		(5)
Total trading gains	$	22	$	20

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 September 30, 2025	$	205	$	105	$	27	$	64	$	(5)	$	396
Three months ended September 30, 2024	170		102		61		67		1		401

Operations and maintenance expense decreased by $5 million for the three months ended September 30, 2025, compared to the same period in 2024, due to the following:


	(In millions)
Decrease driven by the expiration of the Cottonwood facility lease in May 2025	$	(28)
Decrease due to the disposition of Services businesses	(15)
Decrease in retail operations costs	(7)
Increase in planned major maintenance expenditures associated with the scope of outages at the Texas gas facilities and Powerton	35
Increase due to the acquisition of the Texas Generation Portfolio facilities in April 2025	7
Other	3
Decrease in operations and maintenance expense	$	(5)

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 September 30, 2025	$	67	$	34	$	—	$	1	$	102
Three months ended September 30, 2024	80		46		4		2		132

Other cost of operations for the three months ended September 30, 2025 decreased by $30 million, when compared to the same period in 2024, due to the following:


	(In millions)
Decrease primarily due to changes in prior year ARO cost estimates at Jewett Mine and in the East	$	(24)
Other	(6)
Decrease in other cost of operations	$	(30)

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 September 30, 2025	$	95	$	37	$	10	$	207	$	11	$	360
Three months ended September 30, 2024	81		39		23		198		11		352

Depreciation and amortization increased by $8 million for the three months ended September 30, 2025, compared to the same period in 2024, due to the following:


	(In millions)
Increase in amortization of capitalized contract costs primarily in the Vivint Smart Home segment	$	46
Decrease in amortization driven by the expected roll off of the acquired Vivint Smart Home intangibles	(31)
Decrease in amortization due to the disposition of Services businesses	(5)

Other	(2)
Increase in depreciation and amortization	$	8

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 September 30, 2025	$	261	$	151	$	44	$	148	$	8	$	612
Three months ended September 30, 2024	260		157		66		151		11		645

Selling, general and administrative costs decreased by $33 million for the three months ended September 30, 2025, compared to the same period in 2024, due to the following:


	(In millions)
Decrease due to the disposition of Services businesses	$	(13)
Decrease in equity linked compensation	(7)
Decrease in provision for credit losses due to improved customer payment behavior	(7)
Decrease in personnel costs	(4)

Other	(2)
Decrease in selling, general and administrative costs	$	(33)

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $8 million and $7 million for the three months ended September 30, 2025 and 2024, respectively, include:


	Three months ended September 30,
(In millions)	2025		2024
Vivint Smart Home integration costs	$	4	$	4
LSP Portfolio acquisition costs	2		—



Other	2		3
Acquisition-related transaction and integration costs	$	8	$	7

Gain on Sale of Assets

The gain on sale of assets of $208 million for the three months ended September 30, 2024, was due to the sale of the Airtron business unit.

Interest Expense

Interest expense decreased by $26 million for the three months ended September 30, 2025, compared to the same period in 2024, primarily due to higher unrealized losses on derivatives related to debt assumed at the Vivint acquisition in the 2024 period, partially offset by a realized loss on the treasury locks in the 2025 period.

Income Tax Expense/(Benefit)

For the three months ended September 30, 2025, income tax expense of $86 million was recorded on pre-tax income of $238 million. For the same period in 2024, an income tax benefit of $247 million was recorded on pre-tax loss of $1.0 billion. The effective tax rates were 36.1% and 24.4% for the three months ended September 30, 2025 and 2024, respectively.

For the three months ended September 30, 2025 and 2024, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense.

Management’s discussion of the results of operations for the nine months ended September 30, 2025 and 2024

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2025 and 2024:


	Average on Peak Power Price ($/MWh)
	Nine months ended September 30,
Region	2025		2024		Change %
Texas
ERCOT - Houston (a)	$	38.79	$	34.09	14	%
ERCOT - North(a)	36.73		32.19		14	%

East
NY J/NYC(b)	$	76.07	$	42.79	78	%
NEPOOL(b)	72.48		42.62		70	%
COMED (PJM)(b)	46.17		32.50		42	%
PJM West Hub(b)	58.13		41.07		42	%

West
MISO - Louisiana Hub(b)	$	45.49	$	29.78	53	%
CAISO - SP15(b)	26.55		28.17		(6)	%

(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 nine months ended September 30, 2025 and 2024:


	Nine months ended September 30,
	2025		2024		Change %
($/MMBtu)	$	3.39	$	2.10	61	%

Gross Margin

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 management. 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.

The following tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2025 and 2024:


	Nine months ended September 30, 2025
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	8,466	$	9,724	$	2,350	$	1,530	$	(53)	$	22,017
Energy revenue	38		354		101		—		(1)		492
Capacity revenue	—		182		14		—		(1)		195
Mark-to-market for economic hedging activities	—		12		6		—		—		18
Contract amortization	—		(4)		—		—		—		(4)
Other revenue(a)	157		76		18		—		(9)		242
Total revenue	8,661		10,344		2,489		1,530		(64)		22,960
Cost of fuel	(652)		(203)		(73)		—		—		(928)
Purchased energy and other cost of sales(b)(c)(d)	(4,942)		(8,635)		(2,001)		(143)		23		(15,698)
Mark-to-market for economic hedging activities	(375)		(46)		75		—		—		(346)
Contract and emissions credit amortization	(11)		(27)		(5)		—		—		(43)
Depreciation and amortization	(271)		(110)		(34)		$	(582)	(33)		(1,030)
Gross margin	$	2,410	$	1,323	$	451	$	805	$	(74)	$	4,915
Less: Mark-to-market for economic hedging activities, net	(375)		(34)		81		—		—		(328)
Less: Contract and emissions credit amortization, net	(11)		(31)		(5)		—		—		(47)
Less: Depreciation and amortization	(271)		(110)		(34)		(582)		(33)		(1,030)
Economic gross margin	$	3,067	$	1,498	$	409	$	1,387	$	(41)	$	6,320
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.6 billion, $186 million and $817 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)	31,021		11,775		1,844		—		—		44,640
Business electricity sales volume (GWh)	30,055		34,627		9,415		—		—		74,097
Home natural gas sales volume (MDth)	—		35,557		48,109		—		—		83,666
Business natural gas sales volume (MDth)	—		1,107,780		132,099		—		—		1,239,879
Average retail Home customer count (in thousands)(a)	2,911		2,172		717		—		—		5,800
Ending retail Home customer count (in thousands)(a)	2,844		2,115		714		—		—		5,673
Average Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,229		—		2,229
Ending Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,351		—		2,351
Power generation
GWh sold	21,880		4,804		2,117		—		—		28,801
GWh generated(c)
Coal	16,302		2,945		—		—		—		19,247
Gas	5,578		5		2,114		—		—		7,697

Oil	—		15		—		—		—		15
Renewables	—		—		3		—		—		3
Total	21,880		2,965		2,117		—		—		26,962
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments. Cottonwood was leased until May 2025


	Nine months ended September 30, 2024
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	8,101	$	8,257	$	2,747	$	1,434	$	(12)	$	20,527
Energy revenue	35		194		170		—		(9)		390
Capacity revenue	—		120		16		—		(3)		133
Mark-to-market for economic hedging activities	—		15		14		—		3		32
Contract amortization	—		(23)		(2)		—		—		(25)
Other revenue(a)	161		84		17		—		(8)		254
Total revenue	8,297		8,647		2,962		1,434		(29)		21,311
Cost of fuel	(471)		(98)		(79)		—		—		(648)
Purchased energy and other cost of sales(b)(c)(d)	(5,212)		(7,078)		(2,342)		(108)		17		(14,723)
Mark-to-market for economic hedging activities	(707)		595		(200)		—		(3)		(315)
Contract and emissions credit amortization	(7)		(31)		(5)		—		—		(43)
Depreciation and amortization	(240)		(117)		(96)		$	(561)	(31)		(1,045)
Gross margin	$	1,660	$	1,918	$	240	$	765	$	(46)	$	4,537
Less: Mark-to-market for economic hedging activities, net	(707)		610		(186)		—		—		(283)
Less: Contract and emissions credit amortization, net	(7)		(54)		(7)		—		—		(68)
Less: Depreciation and amortization	(240)		(117)		(96)		(561)		(31)		(1,045)
Economic gross margin	$	2,614	$	1,479	$	529	$	1,326	$	(15)	$	5,933
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.6 billion, $197 million and $860 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)	31,540		11,803		1,722		—		—		45,065
Business electricity sales volume (GWh)	30,936		35,792		7,985		—		—		74,713
Home natural gas sales volume (MDth)	—		33,577		50,027		—		—		83,604
Business natural gas sales volume (MDth)	—		1,118,695		134,310		—		—		1,253,005
Average retail Home customer count (in thousands)(a)	2,949		2,168		761		—		—		5,878
Ending retail Home customer count (in thousands)(a)	2,921		2,132		718		—		—		5,771
Average Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,083		—		2,083
Ending Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,154		—		2,154
Power generation
GWh sold	16,913		3,639		4,342		—		—		24,894
GWh generated(c)
Coal	10,353		2,005		—		—		—		12,358
Gas	6,560		1		4,338		—		—		10,899

Oil	—		4		—		—		—		4
Renewables	—		—		4		—		—		4
Total	16,913		2,010		4,342		—		—		23,265
(a) Home customer count includes recurring residential customers, services customers and community choice
(b) Vivint Smart Home customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments

The following table represents the weather metrics for the nine months ended September 30, 2025 and 2024:


	Nine months ended September 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2025
CDDs(a)	2,913	1,184	1,780
HDDs(a)	1,063	3,004	1,379
2024
CDDs	3,003	1,277	1,881
HDDs	916	2,676	1,310
10-year average
CDDs	2,851	1,251	1,811
HDDs	993	2,970	1,292

(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 $378 million and economic gross margin increased $387 million, both of which include intercompany sales, during the nine months ended September 30, 2025, compared to the same period in 2024.

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

Texas


	(In millions)
Higher gross margin due to the following: •an increase in net revenue of $319 million, primarily driven by changes in customer term, product and mix •a 6%, or $159 million decrease in cost to serve the retail load, driven by lower realized power prices associated with the Company's diversified supply strategy	$	478
Lower gross margin due to a decrease in load of 1.7 TWh, or $50 million, driven by changes in customer mix and attrition, partially offset by an increase in load of 300 GWh, or $16 million attributed to weather	(34)
Other	9


Increase in economic gross margin	$	453
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	332
Increase in contract and emissions credit amortization	(4)
Increase in depreciation and amortization	(31)
Increase in gross margin	$	750

East


	(In millions)
Lower gross margin due to the deactivation of Indian River Unit 4 in February 2025	$	(37)
Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in higher net revenue rates from changes in customer term, product, and mix of $1.05 per Dth, or $1.19 billion, partially offset by higher supply costs of $0.90 per Dth, or $1.04 billion, driven by an increase in gas costs	145

Lower natural gas gross margin from a decrease in load due to a change in customer mix, partially offset by an increase in load due to weather	(5)
Lower electric gross margin due to higher supply costs of $12.50 per MWh, or $584 million driven primarily by increases in power prices, partially offset by higher net revenue rates of $9.00 per MWh, or $408 million, as a result of changes in customer term, product and mix	(176)
Lower electric gross margin from a decrease in load due to a change in customer mix, partially offset by an increase in load due to weather	(7)

Higher gross margin due to an increase in generation volumes as a result of spark spread expansion in NYISO, partially offset by a decrease in average realized prices at Midwest Generation	31
Higher gross margin due to a 159% increase in PJM capacity prices and a 37% increase in NYISO capacity prices	60
Higher gross margin from demand response, primarily as a result of curtailment events during the third quarter of 2025	9
Other	(1)
Increase in economic gross margin	$	19
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(644)
Decrease in contract amortization	23
Decrease in depreciation and amortization	7
Decrease in gross margin	$	(595)

West/Services/Other


	(In millions)
Lower gross margin due to the disposition of Services businesses	$	(121)
Higher electric gross margin due to lower supply costs of $13.50 per MWh, or $154 million and customer mix of $25 million, partially offset by lower net revenue rates of $11.00 per MWh, or $123 million	56
Higher natural gas gross margin due to higher net revenue rates of $0.05 per Dth, or $5 million and lower supply costs of $0.05 per Dth, or $4 million	9
Higher gross margin primarily due to an increase in home protection plan sales	34
Lower gross margin at Cottonwood driven by the termination of the facility lease in May 2025	(83)

Lower gross margin at Cottonwood due to spark spread contraction, partially offset by favorable capacity pricing	(12)
Other	(3)
Decrease in economic gross margin	$	(120)
Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges	267
Decrease in contract amortization	2
Decrease in depreciation and amortization	62
Increase in gross margin	$	211

Vivint Smart Home


	(In millions)
Higher gross margin primarily driven by growth in customers of $85 million and higher revenue rates of $0.96 per customer, or $19 million	$	104
Lower gross margin due to a decrease in non-recurring sales revenue	(25)
Lower gross margin due to an increase in personnel and related support costs	(9)
Other	(9)
Increase in economic gross margin	$	61


Increase in depreciation and amortization	(21)
Increase in gross margin	$	40

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 decreased by $45 million during the nine months ended September 30, 2025, compared to the same period in 2024.

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


	Nine months ended September 30, 2025
(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	$	—	$	(7)	$	6	$	—	$	(1)

Net unrealized gains on open positions related to economic hedges	—		19		—		—		19
Total mark-to-market gains in revenue	$	—	$	12	$	6	$	—	$	18
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)	$	(498)	$	(96)	$	143	$	—	$	(451)
Reversal of acquired loss/(gain) positions related to economic hedges	23		(2)		—		—		21
Net unrealized gains/(losses) on open positions related to economic hedges	100		52		(68)		—		84
Total mark-to-market (losses)/gains in operating costs and expenses	$	(375)	$	(46)	$	75	$	—	$	(346)

(a)Includes $(319) million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities


	Nine months ended September 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	$	—	$	(28)	$	—	$	3	$	(25)
Reversal of acquired (gain) positions related to economic hedges	—		(1)		—		—		(1)
Net unrealized gains on open positions related to economic hedges	—		44		14		—		58
Total mark-to-market gains in revenue	$	—	$	15	$	14	$	3	$	32
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(616)	$	628	$	55	$	(3)	$	64
Reversal of acquired loss/(gain) positions related to economic hedges	2		(5)		1		—		(2)
Net unrealized (losses) on open positions related to economic hedges	(93)		(28)		(256)		—		(377)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(707)	$	595	$	(200)	$	(3)	$	(315)

For the nine months ended September 30, 2025, the $18 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 prices. The $346 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, partially offset by an increase in the value of Texas open positions as a result of increases in ERCOT power prices.

For the nine months ended September 30, 2024, the $32 million gain in revenues from economic hedge positions was primarily driven by an increase in the value of open positions as a result of decreases in power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $315 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in power prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 30, 2025 and 2024. 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.


	Nine months ended September 30,
(In millions)	2025		2024
Trading gains
Realized	$	26	$	30
Unrealized	7		—
Total trading gains	$	33	$	30

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Nine months ended September 30, 2025	$	534	$	303	$	118	$	181	$	(18)	$	1,118
Nine months ended September 30, 2024	585		259		168		178		2		1,192

Operations and maintenance expense decreased by $74 million for the nine months ended September 30, 2025, compared to the same period in 2024, due to the following:


	(In millions)
Decrease due to the final property insurance claim for the extended outage at W.A. Parish received in 2025	$	(100)
Decrease due to the disposition of Services businesses	(53)
Decrease driven by the expiration of the Cottonwood facility lease in May 2025	(28)
Increase in planned major maintenance expenditures associated with the scope of outages at the Powerton and Cottonwood, partially offset by the timing of planned outages at the Texas coal facilities	61
Increase driven by higher retail operations costs	16

Increase due to the acquisition of the Texas Generation Portfolio facilities in April 2025	14
Increase in variable operations and maintenance expenditures driven by higher generation at Powerton	6
Increase driven by higher Vivint Smart Home operations costs to support customer growth	3

Other	7
Decrease in operations and maintenance expense	$	(74)

Other Cost of Operations

Other Cost of operations are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Total
Nine months ended September 30, 2025	$	192	$	97	$	6	$	3	$	298
Nine months ended September 30, 2024	187		104		11		6		308

Other cost of operations decreased by $10 million for the nine months ended September 30, 2025, compared to the same period in 2024, due to the following:


	(In millions)
Decrease primarily driven by current year changes in ARO cost estimates in the East, partially offset by an increase in current year ARO cost estimates at Jewett Mine	$	(7)



Other	(3)
Decrease in other cost of operations	$	(10)

Depreciation and Amortization

Depreciation and amortization expenses are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Total
Nine months ended September 30, 2025	$	271	$	110	$	34	$	582	$	33	$	1,030
Nine months ended September 30, 2024	240		117		96		561		31		1,045

Depreciation and amortization decreased by $15 million for the nine months ended September 30, 2025, compared to the same period in 2024, due to the following:


	(In millions)
Increase in amortization of capitalized contract costs primarily in the Vivint Smart Home segment	$	132
Decrease in amortization driven by the expected roll off of the acquired Vivint Smart Home intangibles	(91)
Decrease in amortization due to the disposition of Services businesses	(37)
Decrease in amortization primarily due to the roll off of intangibles in Texas, East and West	(22)
Other	3
Decrease in depreciation and amortization	$	(15)

Selling, General and Administrative Costs

Selling, general and administrative costs comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Nine months ended September 30, 2025	$	677	$	445	$	130	$	618	$	15	$	1,885
Nine months ended September 30, 2024	622		435		187		460		35		1,739

Selling, general and administrative costs increased by $146 million for the nine months ended September 30, 2025, compared to the same period in 2024, due to the following:


	(In millions)
Increase due to reserves for legal matters in 2025	$	176
Increase in equity linked compensation primarily driven by a higher share price in 2025	24
Increase in personnel costs	24

Decrease due to the disposition of Services businesses	(35)
Decrease in provision for credit losses primarily due to improved customer payment behavior	(27)
Decrease in marketing and media expenses	(8)
Other	(8)
Increase in selling, general and administrative costs	$	146

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $59 million and $22 million for the nine months ended September 30, 2025 and 2024, respectively, include:


	Nine months ended September 30,
(In millions)	2025		2024
LSP Portfolio acquisition costs	$	25	$	—

Vivint Smart Home integration costs	25		17
Texas Generation Portfolio acquisition costs	5		—

Other	4		5
Acquisition-related transaction and integration costs	$	59	$	22

Gain on Sale of Assets

The gain on sale of assets of $209 million for the nine months ended September 30, 2024, was primarily due to the sale of the Airtron business unit.

Loss on Debt Extinguishment

A loss on debt extinguishment of $260 million was recorded for the nine months ended September 30, 2024, driven by the repurchase of a portion of the Convertible Senior Notes.

Interest Expense

Interest expense decreased by $30 million for the nine months ended September 30, 2025, compared to the same period in 2024, primarily due to higher unrealized losses on derivatives and amortization of debt discount related to debt assumed at the Vivint acquisition in the 2024 period, partially offset by a realized loss on the treasury locks in the 2025 period.

Income Tax Expense

For the nine months ended September 30, 2025, an income tax expense of $272 million was recorded on a pre-tax income of $1.1 billion. For the same period in 2024, income tax expense of $251 million was recorded on pre-tax income of $733 million. The effective tax rates were 25.4% and 34.2% for the nine months ended September 30, 2025 and 2024, respectively.

For the nine months ended September 30, 2025, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense, partially offset with favorable permanent differences. For the same period in 2024, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense and permanent differences.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2025 and December 31, 2024, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $6.5 billion and $5.4 billion, respectively, was comprised of the following:


(In millions)	September 30, 2025		December 31, 2024
Cash and cash equivalents	$	732	$	966
Restricted cash - operating	15		4
Restricted cash - reserves(a)	15		4
Total	762		974
Total availability under Revolving Credit Facility and collective collateral facilities(b)	5,730		4,469
Total liquidity, excluding funds deposited by counterparties	$	6,492	$	5,443

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

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $8.0 billion and $7.3 billion as of September 30, 2025 and December 31, 2024, respectively

For the nine months ended September 30, 2025, total liquidity, excluding funds deposited by counterparties, increased by $1.0 billion. Changes in cash and cash equivalent balances are further discussed under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, 2025 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.

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, Senior Secured First Lien Notes, Senior Credit Facility, Receivables Facility and tax-exempt bonds. The Company also issues letters of credit through bilateral letter of credit facilities and the pre-capitalized trust securities facility.

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.

Anticipated Acquisition of LSP Portfolio

On May 12, 2025, NRG entered into a definitive agreement with LS Power to acquire a power portfolio including 13 GW of natural gas-fired generation facilities and the C&I VPP platform with 6 GW of capacity. The consideration will consist of 24.25 million shares of NRG common stock, and $6.4 billion in cash, subject to working capital adjustments as set forth in the purchase agreement. As part of the transaction, NRG will also assume approximately $3.2 billion of debt. The acquisition is expected to close in the first quarter of 2026 and is subject to the satisfaction or waiver of specified closing conditions, consents and regulatory approvals, including HSR, FERC, DOJ, and NYSPSC. For further discussion, see Note 4, Acquisitions and Dispositions.

Acquisition of Texas Generation Portfolio

On April 10, 2025, the Company acquired all of the ownership interests of six power generation facilities from Rockland Capital, LLC, adding 738 MW of natural gas-fired assets in Texas to its portfolio for $560 million in consideration, less $2 million in working capital adjustments. For further discussion, see Note 4, Acquisitions and Dispositions.

Issuance of Unsecured Notes and Secured Notes

Amendment to Term Loan

On July 22, 2025, the Company and APX Group LLC, as borrowers, and certain subsidiaries of the Company, as guarantors, entered into the Fifteenth Amendment with, among others, the Agent, and certain financial institutions, as lenders, which amended the Credit Agreement by adding a new incremental Term Loan B in an aggregate principal amount of $1.0 billion. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Revolving Credit Facility

On May 27, 2025, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Fourteenth Amendment to the Credit Agreement in order to (i) increase the commitments under the Revolving Credit Facility by the Incremental Commitments to an aggregate amount equal to $4.6 billion and (ii) make certain other amendments to the Credit Agreement. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Convertible Senior Notes Redemption

On May 15, 2025, the Company issued a notice of redemption for the Convertible Senior Notes. On the Redemption Date, the Company used cash on hand to redeem $12 million in aggregate principal amount of the Convertible Senior Notes, at a redemption price equal to 100.000%. The majority of the Convertible Senior Note holders elected to convert the notes prior to the Redemption Date and received $220 million in cash with respect to the remaining principal amount of the Convertible Senior Notes and a total of 3,986,335 shares for the conversion premium. See Note 7, Long-term Debt and Finance Leases.

Receivables Securitization Facilities

On June 20, 2025, NRG Receivables amended its existing Receivables Facility to extend the scheduled termination date to June 18, 2026.

Texas Development Priorities

On July 31, 2025, NRG THW GT LLC, a wholly-owned subsidiary of the Company, entered into the First TEF loan to support the development of T.H. Wharton, which is currently under construction. The Company signed an Equity Contribution Agreement and Guaranty with respect to the First TEF Loan. The loan bears interest at a fixed rate of 3.000% per annum and has a final maturity date of July 31, 2045. As of October 31, 2025, $178 million of disbursements for the First TEF loan have occurred.

On September 26, 2025, NRG Cedar Bayou 5 LLC, a wholly-owned subsidiary of the Company, entered into the Second TEF loan to support the development of Cedar Bayou 5, which is currently under construction. The Company signed an Equity Contribution Agreement and Guaranty with respect to the Second TEF Loan. The loan bears interest at a fixed rate of 3.000% per annum and has a final maturity date of September 26, 2045. As of October 31, 2025, $230 million of disbursements for the Second TEF loan have occurred.

IR Bonds

On October 23, 2025, the Company remarketed $57 million aggregate principal amount of the IR 2040 Bonds and $190 million aggregate principal amount of the IR 2045 Bonds. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Liability Management

The Company has currently spent $269 million and intends to spend approximately $6 million from cash from operations on liability management during the remainder of 2025. The Company remains committed to maintaining a strong balance sheet and its targeted credit metrics.

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 September 30, 2025, market operations had total cash collateral outstanding of $358 million and $2.2 billion outstanding in letters of credit to third parties primarily to support its market activities. As of September 30, 2025, total funds deposited by counterparties were $323 million in cash and $339 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 are dependent 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 exceed the hedged prices. As of September 30, 2025, all hedges under the first liens were at-the-money on a counterparty aggregate basis.

Capital Expenditures

The following table summarizes the Company's capital expenditures for maintenance, environmental and investments and integration for the nine months ended September 30, 2025, and the estimated forecast for the remainder of the year.


(In millions)	Maintenance		Environmental		Investments and Integration		Total
Texas	$	175	$	26	$	529	$	730
East	9		—		—		9
West/Services/Other	8		—		1		9
Vivint Smart Home	10		—		4		14
Corporate	17		—		70		87
Total cash capital expenditures for the nine months ended September 30, 2025(a)	$	219	$	26	$	604	$	849
Integration operating expenses and cost to achieve	—		—		32		32
Investments	—		—		181		181
Total cash capital expenditures and investments for the nine months ended September 30, 2025	$	219	$	26	$	817	$	1,062




Estimated cash capital expenditures and investments for the remainder of 2025	171		19		126		316
Estimated full year 2025 cash capital expenditures and investments	$	390	$	45	$	943	$	1,378

(a)Capital expenditures exclude W.A. Parish insurance proceeds of $100 million

Investments and Integration for the nine months ended September 30, 2025 include growth expenditures, integration, small book acquisitions and other investments.

Environmental Capital Expenditures Estimate

NRG estimates that environmental capital expenditures from 2025 through 2029 required to comply with environmental laws will be approximately $76 million, primarily driven by the cost of complying with ELG at the Company's coal units in Texas.

Share Repurchases

Common Stock Dividends

Series A Preferred Stock Dividends

During the quarters ended September 30, and March 31, 2025, the Company declared and paid a semi-annual 10.25% dividend of $51.25 per share on its outstanding Series A Preferred Stock, each 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 26, Guarantees, to the Company's 2024 Form 10-K.

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 September 30, 2025. 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 2024 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 nine months ended September 30, 2025.

Cash Flow Discussion

The following table reflects the changes in cash flows for the nine months ended September 30, 2025 and 2024, respectively:


	Nine months ended September 30,
(In millions)	2025		2024		Change
Cash provided by operating activities	$	1,790	$	1,354	$	436
Cash (used)/provided by investing activities	(1,340)		163		(1,503)
Cash used by financing activities	(540)		(1,041)		501

Cash provided by operating activities

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


	(In millions)




Increase in operating income adjusted for other non-cash items	$	349
Increase in working capital primarily driven by deferred revenues and changes in ARO cost estimates	225
Decrease in working capital due to the payment of the CPI legal matter	(224)
Changes in cash collateral in support of risk management activities due to change in commodity prices	156
Decrease in working capital primarily due to timing of prepayments	(99)








Increase in other working capital	29
	$	436

Cash (used)/provided by investing activities

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


	(In millions)




Increase in capital expenditures	$	(563)
Increase in cash paid for acquisitions primarily due to the acquisition of the Texas Generation Portfolio in April 2025	(558)
Decrease in proceeds from sale of assets primarily due to the sale of the Airtron business unit in 2024	(489)
Increase in insurance proceeds for property, plant and equipment, net	97

Increase due to fewer purchases of emissions allowances, net of sales	10
	$	(1,503)

Cash used by financing activities

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


	(In millions)




Increase due to fewer repayments of long-term debt and finance leases	$	711
Decrease primarily due to higher payments for share repurchase activity in 2025	(683)
Increase in proceeds from issuance of long-term debt in 2025	500
Decrease due to payment for settlement of capped call options in 2025	(292)
Increase primarily due to debt extinguishment costs in 2024	216
Increase in net receipts from settlement of acquired derivatives	53
Other	(4)



	$	501

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

For the nine months ended September 30, 2025, the Company had domestic pre-tax book income of $978 million and foreign pre-tax book income of $92 million. As of December 31, 2024, the Company had cumulative U.S. federal NOL carryforwards of $7 billion, of which $5.3 billion do not have an expiration date, and cumulative state NOL carryforwards of $6.1 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $394 million, most of which do not have an expiration date. In addition to the above NOLs, NRG has a $274 million indefinite carryforward for interest deductions, as well as $269 million of tax credits, inclusive of $61 million CAMT 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 $125 million in 2025. NRG as an applicable corporation is subject to the CAMT, however, there is no impact on the Company's provision for income taxes from the CAMT for the nine months ended September 30, 2025.

As of September 30, 2025, the Company has $57 million of tax-effected uncertain federal, state, and foreign tax benefits, for which the Company has recorded a non-current tax liability of $62 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 2021. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2015.

On July 4, 2025, OBBB was enacted into law. The OBBB includes changes to U.S. tax law that will be applicable to NRG beginning in 2025, such as the permanent extension of certain expiring provisions of the TCJA, modifications to the international tax framework and the restoration of favorable tax treatment for certain business provisions. The impact of the OBBB on the Company’s consolidated financial statements has been reflected in its third quarter current and deferred taxes, however, there is no material impact to the income tax expense for the nine months ended September 30, 2025.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of September 30, 2025 and December 31, 2024, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.0 billion and $2.2 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 September 30, 2025 and December 31, 2024 as discussed below.

NOL Carryforwards — As of September 30, 2025, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.5 billion and $341 million, respectively. The Company estimates it will 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 $111 million.

Valuation Allowance — As of September 30, 2025 and December 31, 2024, the Company’s tax-effected valuation allowance was $149 million and $144 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 September 30, 2025, the Company's outstanding registered senior notes consisted of $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.

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)	Nine months ended September 30, 2025
Revenue(a)	$	21,035
Operating income(b)	1,327
Total other expense	(450)
Income before income taxes	877
Net Income	631

(a)Intercompany transactions with Non-Guarantors of $37 million during the nine months ended September 30, 2025

(b)Intercompany transactions with Non-Guarantors including cost of operations of $87 million and selling, general and administrative of $334 million during the nine months ended September 30, 2025

The following table presents the summarized balance sheet information:


(In millions)	As of September 30, 2025
Current assets(a)	$	5,499
Property, plant and equipment, net	1,444
Non-current assets	15,492
Current liabilities(b)	7,252
Non-current liabilities	13,589

(a)Includes intercompany receivables due from Non-Guarantors of $194 million as of September 30, 2025

(b)Includes intercompany payables due to Non-Guarantors of $74 million as of September 30, 2025

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 debt, NRG enters into interest rate derivatives. 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, customers 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 customer.

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.

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 September 30, 2025, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2025. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.


Derivative Activity Gains/(Losses)	(In millions)
Fair Value of Contracts as of December 31, 2024	$	992
Contracts realized or otherwise settled during the period	(411)
Texas Generation Portfolio contracts acquired during the period	(83)
Other changes in fair value	(89)
Fair Value of Contracts as of September 30, 2025(a)	$	409

(a)Includes $450 million of derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities


	Fair Value of Contracts as of September 30, 2025
(In millions)	Maturity
Fair Value Hierarchy (Losses)/Gains(a)	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	$	(4)	$	7	$	1	$	(1)	$	3
Level 2	56		93		21		4		174
Level 3	(121)		(106)		(7)		16		(218)
Total	$	(69)	$	(6)	$	15	$	19	$	(41)

(a)Excludes $450 million of derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities

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 September 30, 2025, NRG's net derivative asset was $409 million, a decrease to total fair value of $583 million as compared to December 31, 2024. This decrease was driven by the roll-off of trades that settled during the period, losses in fair value and the Texas Generation Portfolio contracts acquired.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $957 million in the net value of derivatives as of September 30, 2025. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $953 million in the net value of derivatives as of September 30, 2025.

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.

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 2024 Form 10-K. There have been no material changes to the Company's critical accounting estimates since the 2024 Form 10-K.

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 2024 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 nine months ended September 30, 2025 and 2024:


(In millions)	2025		2024
VaR as of September 30,	$	65	$	67
Three months ended September 30,
Average	$	67	$	58
Maximum	76		67
Minimum	57		50
Nine months ended September 30,
Average	$	62	$	61
Maximum	76		75
Minimum	47		50

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 $84 million, as of September 30, 2025, 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


	Net Exposure(a)(b)
Category by Industry Sector	(% of Total)

Utilities, energy merchants, marketers and other	67	%
Financial institutions	33

Total as of September 30, 2025	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	73	%
Non-investment grade/Non-Rated	27
Total as of September 30, 2025	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

RTOs and ISOs

Exchange Traded Transactions

Long-Term Contracts

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.

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 September 30, 2025, 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 $859 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 $280 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2025.

Interest Rate Risk

NRG is exposed to fluctuations in interest rates through its issuance of debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, treasury locks, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility when taking into account the combinations of the debt and the interest rate derivative instrument. NRG's management policies allow the Company to reduce interest rate exposure. The Company has $700 million of interest rate swaps extending through 2029 to mitigate the risk of the floating rate of the Term Loan B. In July 2025, the Company entered into treasury locks with a total notional amount of $1.4 billion which were fully terminated in September 2025.

NRG has both short and long-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of September 30, 2025, a 1% change in variable interest rates would result in a $16 million change in interest expense on a rolling twelve-month basis.

As of September 30, 2025, the fair value and related carrying value of the Company's debt was $11.8 billion and $12.0 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 September 30, 2025 by $466 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 September 30, 2025, 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 $425 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 September 30, 2025 would have resulted in a decrease of $6 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 September 30, 2025 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings to which NRG is a party through September 30, 2025, see Note 14, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

Except as set forth below, there have been no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company's 2024 Form 10-K.

Risks Related to the Anticipated Acquisition of the LSP Portfolio

The Company may encounter difficulties in satisfying the closing conditions set forth in the purchase agreement relating to the anticipated acquisition of the LSP Portfolio, including obtaining the necessary governmental and regulatory approvals, within the expected time frame or at all.

Consummation of the acquisition of the LSP Portfolio is subject to the satisfaction or waiver of certain closing conditions, including: (i) the receipt of required governmental and regulatory approvals; (ii) the expiration or termination of the applicable waiting period under the HSR Act; and (iii) other customary closing conditions. Completion of the acquisition is conditioned upon the receipt of various consents, orders, approvals or clearances from various regulatory authorities, including DOJ, FERC, and public utility commissions or similar entities in certain states in which the LSP Portfolio operates.

The Company cannot provide assurance that all required regulatory approvals will be obtained, in a timely manner or at all, or that these approvals will not contain terms, conditions or restrictions that would be unacceptable and, accordingly, the acquisition may be delayed or may not be consummated.

The purchase agreement with LS Power provides that either NRG or LS Power could terminate the LSP Portfolio purchase agreement if the acquisition is not completed by May 12, 2026 (which date may be automatically extended for up to six consecutive one-month periods). If the agreement is terminated under certain circumstances due to the failure to obtain regulatory approvals or if there are any legal restraints prohibiting the consummation of the acquisition, NRG would be required to pay LS Power a termination fee of $400 million as liquidated damages.

In the event the transaction is not consummated, the share price of NRG common stock may decline to the extent that the current market price reflects an assumption by the market that the acquisition will be completed.

The Company may not realize all the expected benefits of the acquisition.

The Company entered into the purchase agreement with LS Power with the expectation that the acquisition would result in various benefits, including enhanced generation capabilities. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, including whether the assets and businesses of NRG and the LSP Portfolio can be integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs and/or lower-than-expected revenues or income generated by the Company after the completion of the acquisition.

The assets, liabilities and results of operations of LSP Portfolio could be negatively affected by unknown or unexpected events, conditions or actions prior to the closing of the acquisition.

The Company will not control the LSP Portfolio until completion of the anticipated acquisition and the assets, liabilities, business, financial condition, cash flows, operating results and prospects of the LSP Portfolio to be acquired or assumed by the Company could be negatively impacted before or after the closing as a result of previously unknown events or conditions occurring or existing before the acquisition closes. Adverse changes in its business or operations could occur or arise as a result of actions undertaken by LS Power, legal or regulatory developments, deteriorating general business, market, industry or economic conditions, and other factors both within and beyond the control of LS Power or NRG. A significant decline in the value of the assets to be acquired or a significant increase in the liabilities to be assumed could negatively impact the Company’s future business, operating results, cash flows, financial conditions or prospects following the completion of the acquisition. In addition, there could be potential unknown liabilities and unforeseen expenses as a result of the acquisition, some of which NRG may not discover during due diligence or adequately adjust for in the purchase arrangements.

The market price of shares of the Company’s common stock may be adversely affected as a result of the anticipated LSP Portfolio acquisition.

On completion of the anticipated LSP Portfolio acquisition, a significant number of additional shares of the Company’s common stock will be issued and available for trading in the public market. The increase in the number of shares of the

Company’s common stock may lead to sales of such shares or the perception that such sales may occur which may adversely affect the market for, and the market price of, shares of the Company’s common stock.

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 September 30, 2025.


For the three months ended September 30, 2025	Total Number of Shares Purchased(a)	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)(c)(d)
Month #1
(July 1, 2025 to July 31, 2025)	5,199,669	$	85.53	1,213,334	$	857
Month #2
(August 1, 2025 to August 31, 2025)	775,540	$	153.39	775,540	$	738
Month #3
(September 1, 2025 to September 30, 2025)	516,063	$	162.09	516,063	$	654

Total at September 30, 2025	6,491,272	$	99.73	2,504,937

(a)Includes share repurchases under the $3.7 billion share repurchase authorization and the settlement of Capped Call Options. For further discussion, see Note 9, Changes in Capital Structure

(b)The average price paid per share excludes excise tax owed and commissions per share paid in connection with the open market share repurchases

(c)Includes commissions paid in connection with the open market share repurchases

(d)Excludes the additional share repurchase program of up to $3.0 billion authorized by the Board of Directors on October 16, 2025, to be executed through 2028

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 September 30, 2025, 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

Virginia Kinney

Executive Vice President, Chief Administration Officer

8/8/2025

Rule 10b5-1 Trading Arrangement

Up to 25,000 shares to be Sold

11/14/2025-5/15/2026

N/A

Brian Curci

Executive Vice President and General Counsel

8/8/2025

Rule 10b5-1 Trading Arrangement

Up to 107,220(b) shares to be Sold

1/5/2026-7/31/2026

N/A

Robert Gaudette

Executive Vice President, NRG Business

9/4/2025

Rule 10b5-1 Trading Arrangement

Up to 45,000 shares to be Sold

1/5/2026-2/28/2026

N/A

Woo-Sung Chung

Executive Vice President and Chief Financial Officer

9/4/2025

Rule 10b5-1 Trading Arrangement

Up to 20,000 shares to be Sold

1/5/2026-3/31/2026

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

(b)Represents approximate number of shares to be sold based on outstanding awards expected to vest during the period, where certain underlying performance share awards are being calculated at target. Actual number of shares to be sold will depend on actual vesting, the number of shares withheld by NRG to satisfy tax withholding obligations and vesting of dividend equivalent rights

ITEM 6 — EXHIBITS

Number

Description

Method of Filing

4.1

Base Indenture, dated October 8, 2025, between NRG Energy, Inc. and Deutsche Bank Trust Company Americas, as trustee, pertaining to the New Secured Notes.

Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on October 8, 2025.

4.2

Supplemental Indenture, dated October 8, 2025, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Trust Company Americas, as trustee, containing Form of 4.734% Senior Secured First Lien Notes due 2030 and Form 5.407% Senior Secured First Lien Notes due 2035.

Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on October 8, 2025.

4.3

Base Indenture, dated October 8, 2025, between NRG Energy, Inc. and Deutsche Bank Trust Company Americas, as trustee, pertaining to the New Unsecured Notes.

Incorporated herein by reference to Exhibit 4.5 to the Registrant's current report on Form 8-K filed on October 8, 2025.

4.4

Supplemental Indenture, dated October 8, 2025, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Trust Company Americas, as trustee, containing Form of 5.750% Senior Notes due 2034 and Form of 6.000% Senior Notes due 2036.

Incorporated herein by reference to Exhibit 4.6 to the Registrant's current report on Form 8-K filed on October 8, 2025.

10.1

Equity Contribution Agreement and Guaranty, dated September 26, 2025, among NRG Energy, Inc., Cedar Bayou 5 Holdings LLC, NRG Cedar Bayou 5 LLC, Public Utility Commissioner of Texas, and Wilmington Trust, National Association, as administrative agent and collateral agent. *

Filed herewith.

10.2

Credit Agreement, dated September 26, 2025, among NRG Cedar Bayou 5 LLC, Public Utility Commissioner of Texas, and Wilmington Trust, National Association, as administrative agent and collateral agent.*

Filed herewith.

10.3

Fifteenth Amendment to Second Amended and Restated Credit Agreement, dated as of July 22, 2025, among NRG Energy, Inc., Citicorp North America, Inc., as administrative agent and as collateral agent, and certain financial institutions, as lenders*.

Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on July 25, 2025.

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.

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.

•The Schedules and exhibits have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S K. A copy of any omitted schedule or exhibit will be furnished to the Securities and Exchange Commission upon request.

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: November 6, 2025

Chief Accounting Officer

(Principal Accounting Officer)

Source: View Original Filing on SEC EDGAR

FAQ

What were NRG (NRG) Q3 2025 results?

For the quarter ended September 30, 2025, revenue was $7,635 million and net income was $152 million. Operating income was $414 million.

What is NRG (NRG) year-to-date performance in 2025?

For the nine months ended September 30, 2025, revenue was $22,960 million and net income was $798 million.

How many NRG (NRG) shares were outstanding?

As of October 31, 2025, NRG had 191,639,408 common shares outstanding.

What were NRG’s debt balances as of September 30, 2025?

Outstanding Senior Notes were $6.2 billion, and Senior Secured First Lien Notes were $2.6 billion.

What were NRG’s interest expense and preferred dividends in Q3 2025?

Interest expense was $187 million, and cumulative dividends on Series A Preferred Stock were $17 million.

Did NRG mention any major transactions?

Yes. The company referenced an anticipated acquisition of a portfolio of natural gas generation and other assets from LS Power.

What was NRG’s cash balance?

Cash and cash equivalents were $732 million as of September 30, 2025.

[10-Q] NRG ENERGY, INC. Quarterly Earnings Report

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What were NRG (NRG) Q3 2025 results?

What is NRG (NRG) year-to-date performance in 2025?

How many NRG (NRG) shares were outstanding?

What were NRG’s debt balances as of September 30, 2025?

What were NRG’s interest expense and preferred dividends in Q3 2025?

Did NRG mention any major transactions?

What was NRG’s cash balance?

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[10-Q] NRG ENERGY, INC. Quarterly Earnings Report

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Equity analyst – power & utilities neutral

FAQ

What were NRG (NRG) Q3 2025 results?

What is NRG (NRG) year-to-date performance in 2025?

How many NRG (NRG) shares were outstanding?

What were NRG’s debt balances as of September 30, 2025?

What were NRG’s interest expense and preferred dividends in Q3 2025?

Did NRG mention any major transactions?

What was NRG’s cash balance?

NYSE:NRG

NRG Rankings

NRG Latest News

NRG Latest SEC Filings

NRG Stock Data