UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒

Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period Ended:

March 31, 2026

☐

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.)


1301 McKinney Street	Houston	Texas	77010
(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 April 30, 2026, there were 210,986,470 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			71
ITEM 4 — CONTROLS AND PROCEDURES			73
PART II — OTHER INFORMATION			74
ITEM 1 — LEGAL PROCEEDINGS			74
ITEM 1A — RISK FACTORS			74
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			74
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			74
ITEM 4 — MINE SAFETY DISCLOSURES			74
ITEM 5 — OTHER INFORMATION			75
ITEM 6 — EXHIBITS			76
SIGNATURES			77

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, 2025 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, the escalation of international trade disputes, and the occurrence or re-escalation of geopolitical conflicts (including the hostilities with Iran and the conflicts in the Middle East), and inflationary impacts resulting therefrom;

•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 or forced 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, and its counterparties’, ability to successfully complete the development and construction of new generation facilities and 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;

•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 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;

•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:


2025 Form 10-K						NRG’s Annual Report on Form 10-K for the year ended December 31, 2025
ACE						Affordable Clean Energy
Adjusted EBITDA						Adjusted earnings before interest, taxes, depreciation and amortization
AESO						Alberta Electric System Operator
ARO						Asset Retirement Obligation
ASC						The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP

ASU						Accounting Standards Updates – updates to the ASC
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.

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 fuel, 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 portfolio of natural gas and dual fuel 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 March 31, 2026, NRG’s $9.9 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, $950 million of the 6.250% senior notes due 2034, $1.3 billion of the 5.750% senior notes due 2034 and $2.4 billion of the 6.000% senior notes due 2036
Senior Secured First Lien Notes						As of March 31, 2026, NRG’s $3.4 billion outstanding Senior Secured First Lien Notes consists of $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, $625 million of the 4.734% Senior Secured First Lien Notes due 2030, $740 million of the 7.000% Senior Secured First Lien Notes due 2033 and $625 million of the 5.407% Senior Secured First Lien Notes due 2035
Series A Preferred Stock						As of March 31, 2026, 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


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 includes a 1,002 MW natural gas-fueled plant, which is currently operational, and an additional 415 MW natural gas-fueled peaker plant, which is currently under construction
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 March 31,
(In millions, except per share amounts)	2026		2025
Revenue
Revenue	$	10,256	$	8,585
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)	8,858		6,561
Depreciation and amortization	432		326

Selling, general and administrative costs (excluding amortization of customer acquisition costs of $87 and $65, respectively, which are included in depreciation and amortization shown separately above)	593		549

Acquisition-related transaction and integration costs	45		8
Total operating costs and expenses	9,928		7,444

Loss on sale of assets	—		(7)
Operating Income	328		1,134
Other Income/(Expense)


Other income, net	40		14

Interest expense	(285)		(163)
Total other expense	(245)		(149)
Income Before Income Taxes	83		985
Income tax (benefit)/expense	(42)		235


Net Income	$	125	$	750
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17
Net Income Available for Common Stockholders	$	108	$	733
Income per Share
Weighted average number of common shares outstanding — basic	207		198


Income per Weighted Average Common Share — Basic	$	0.52	$	3.70
Weighted average number of common shares outstanding — diluted	208		203


Income per Weighted Average Common Share — Diluted	$	0.52	$	3.61

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three months ended March 31,
(In millions)	2026		2025
Net Income	$	125	$	750
Other Comprehensive (Loss)/Income

Foreign currency translation adjustments	(1)		2

Defined benefit plans	(2)		—
Other comprehensive (loss)/income	(3)		2
Comprehensive Income	$	122	$	752

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31, 2026		December 31, 2025
(In millions, except share data)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	178	$	4,708
Funds deposited by counterparties	176		260
Restricted cash	57		30
Accounts receivable, net	3,777		4,065

Inventory	665		461
Derivative instruments	3,081		2,189
Cash collateral paid in support of energy risk management activities	606		365

Prepayments and other current assets	1,382		1,069


Total current assets	9,922		13,147
Property, plant and equipment, net	13,533		3,632
Other Assets


Operating lease right-of-use assets, net	153		130
Goodwill	8,881		5,017
Customer relationships, net	1,255		1,203
Other intangible assets, net	1,207		1,106

Derivative instruments	1,704		1,568
Deferred income taxes	1,796		1,843
Other non-current assets	1,602		1,494


Total other assets	16,598		12,361
Total Assets	$	40,053	$	29,140


	March 31, 2026		December 31, 2025
(In millions, except share data)	(Unaudited)		(Audited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities

Current portion of long-term debt and finance leases	$	3,375	$	31

Current portion of operating lease liabilities	38		35
Accounts payable	2,485		2,834

Derivative instruments	3,230		2,257
Cash collateral received in support of energy risk management activities	176		260
Deferred revenue current	727		748
Accrued expenses and other current liabilities	1,816		1,864



Total current liabilities	11,847		8,029
Other Liabilities
Long-term debt and finance leases	19,779		16,412
Non-current operating lease liabilities	165		144



Derivative instruments	1,461		1,103
Deferred income taxes	139		15
Deferred revenue non-current	868		895
Other non-current liabilities	920		861


Total other liabilities	23,332		19,430
Total Liabilities	35,179		27,459

Commitments and Contingencies
Stockholders’ Equity
Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at March 31, 2026 and December 31, 2025, aggregate liquidation preference of $650 at March 31, 2026 and December 31, 2025	650		650
Common stock; $0.01 par value; 500,000,000 shares authorized; 224,850,164 and 199,828,615 shares issued and 212,762,887 and 190,376,607 shares outstanding at March 31, 2026 and December 31, 2025, respectively	2		2
Additional paid-in-capital	3,868		215
Retained earnings	1,969		1,982
Treasury stock, at cost; 12,087,277 shares and 9,452,008 shares at March 31, 2026 and December 31, 2025, respectively	(1,531)		(1,087)
Accumulated other comprehensive loss	(84)		(81)

Total Stockholders’ Equity	4,874		1,681
Total Liabilities and Stockholders’ Equity	$	40,053	$	29,140

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three months ended March 31,
(In millions)	2026		2025
Cash Flows from Operating Activities
Net Income	$	125	$	750


Adjustments to reconcile net income to cash (used)/provided by operating activities:
Depreciation of property, plant and equipment and amortization of customer relationships and other intangible assets	277		218
Amortization of capitalized contract costs	155		108
Net accretion of/(gain) on asset retirement obligations	7		(10)
Provision for credit losses	59		56

Amortization of financing costs and debt discounts	5		6

Amortization of in-the-money contracts and emissions allowances	36		44
Amortization of unearned equity compensation	41		29
Net loss on sale of assets and disposal of assets	3		8
Gain on proceeds from insurance recoveries for property, plant and equipment, net	—		(100)


Changes in derivative instruments	190		(320)
Changes in current and deferred income taxes and liability for uncertain tax benefits	(56)		143
Changes in collateral deposits in support of risk management activities	(142)		623




Cash provided/(used) by changes in other working capital:
Accounts receivable - trade	809		(78)
Inventory	(29)		92
Prepayments and other current assets	(196)		(179)
Accounts payable	(910)		(196)
Accrued expenses and other current liabilities	(315)		(185)
Other assets and liabilities	(228)		(154)
Cash (used)/provided by operating activities	$	(169)	$	855


Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets, net of cash acquired	$	(6,755)	$	(20)
Capital expenditures	(317)		(217)

Proceeds from sales of assets	—		6
Net purchases of emissions allowances	—		(3)


Proceeds from insurance recoveries for property, plant and equipment, net	—		100



Cash used by investing activities	$	(7,072)	$	(134)



Cash Flows from Financing Activities

Equivalent shares purchased in lieu of tax withholdings	$	(79)	$	(40)
Payments for share repurchase activity and excise tax	(481)		(314)

Payments of dividends to preferred and common stockholders	(135)		(121)

Proceeds from issuance of long-term debt	57		—
Repayments of long-term debt and finance leases	(12)		(5)

Payments of deferred financing costs	(42)		(3)
Net receipts from settlement of acquired derivatives that include financing elements	19		25



Proceeds from credit facilities	4,850		—
Repayments to credit facilities	(1,525)		—
Cash provided/(used) by financing activities	$	2,652	$	(458)


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

Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(4,587)		265
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	4,998		1,173
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	411	$	1,438

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, 2025	$	650	$	2	$	215	$	1,982	$	(1,087)	$	(81)	$	1,681
Net income							125						125

Other comprehensive loss											(3)		(3)


Share repurchases(a)									(484)				(484)
Retirement of treasury stock(b)					(40)				40				—
Equity-based awards activity, net(c)					(35)								(35)
Issuance of common stock for acquisition of LSP Portfolio(d)					3,728								3,728
Common stock dividends and dividend equivalents declared(e)							(105)						(105)


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


Balance at March 31, 2026	$	650	$	2	$	3,868	$	1,969	$	(1,531)	$	(84)	$	4,874


(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(b)					(179)				179				—
Equity-based awards activity, net(c)					(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

(a)Includes excise tax accrued of $3 million and $2 million for the quarter ended March 31, 2026 and 2025, respectively. See Note 9, Changes in Capital Structure for additional information

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

(c)Includes $(79) million and $(40) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended March 31, 2026 and 2025, respectively

(d)For further discussion of the LSP Portfolio acquisition, see Note 4, Acquisitions

(e)Dividends per common share were $0.475 and $0.440 for each of the quarters ended March 31, 2026 and 2025, respectively

(f)Semi-annual dividends per share of Series A Preferred Stock were $51.25 for each of the periods ended March 15, 2026 and 2025

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, provides electricity, natural gas, and smart-home technology solutions to approximately 8 million residential customers (comprised of 6 million retail energy and 2 million smart home), in addition to large commercial and industrial, data center, and wholesale customers. Across North America, NRG is redefining customers’ experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of March 31, 2026, the Company’s core power and natural gas business consists of approximately 25 GW of competitive power generation, including approximately 13 GW from the LSP Portfolio, and a natural gas portfolio that serves approximately 1,900 MMDth annually.

On January 30, 2026, NRG completed the acquisition of the LSP Portfolio. The LSP Portfolio includes 18 natural gas-fired and dual fuel facilities totaling approximately 13 GW of capacity, located across nine states, as well as CPower, a leading demand response platform. The acquired operations of the LSP Portfolio are integrated into the existing NRG segment structure. Plant and market operations are combined into the corresponding geographical segments of Texas and East. The East segment also includes the customer operations of CPower.

The Company’s business is segmented as follows:

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

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

•West/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) 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 2025 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 March 31, 2026, and the results of operations, comprehensive income, cash flows and stockholders’ equity for the three months ended March 31, 2026 and 2025.

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 March 31,
(In millions)	2026		2025
Amortization of capitalized contract costs related to fulfillment	$	66	$	41
Amortization of capitalized contract costs related to customer acquisition	89		67
Amortization of customer relationships and other intangible assets	130		153
Depreciation of property, plant and equipment	147		65
Total depreciation and amortization	$	432	$	326

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 months ended March 31, 2026 and 2025:


	Three months ended March 31,
(In millions)	2026		2025
Beginning balance	$	146	$	152

Provision for credit losses	59		56
Write-offs	(68)		(79)
Recoveries collected	10		12
Other	3		3
Ending balance	$	150	$	144

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)	March 31, 2026		December 31, 2025
Property, plant and equipment accumulated depreciation	$	1,770	$	1,774
Customer relationships and other intangible assets accumulated amortization	4,118		3,988

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

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


(In millions)	March 31, 2026		December 31, 2025
Cash and cash equivalents	$	178	$	4,708
Funds deposited by counterparties	176		260
Restricted cash	57		30
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	411	$	4,998

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 in their use due to contractual or legal obligations.

Goodwill

The following table represents the changes in goodwill during the three months ended March 31, 2026:


(In millions)	Texas		East		West/Other		Vivint Smart Home		Total
Balance as of December 31, 2025	$	643	$	721	$	130	$	3,523	$	5,017
Goodwill resulting from the acquisition of LSP Portfolio	1,591		2,275		—		—		3,866


Foreign currency translation adjustments	—		—		(2)		—		(2)
Balance as of March 31, 2026	$	2,234	$	2,996	$	128	$	3,523	$	8,881

Recent Accounting Developments — Guidance Adopted in 2026

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. The Company adopted ASU 2024-04 prospectively effective January 1, 2026. The adoption of ASU 2024-04 did not have an impact on the Company’s consolidated financial statements and related 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 Company adopted ASU 2025-05 prospectively effective January 1, 2026. The adoption of ASU 2025-05 did not have a material impact on the Company’s consolidated financial statements and related disclosures.

Recent Accounting Developments — Guidance Not Yet Adopted

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 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.

ASU 2025-08 – In November 2025, the FASB issued ASU No. 2025-08, Financial Instruments—Credit Losses (Topic 326) — Purchased Loans, or ASU 2025-08. The update amends the accounting for “purchased seasoned loans” under Topic 326 by requiring estimated expected credit losses to be reflected as an adjustment to the asset’s purchase price at acquisition. The amendments of ASU 2025-08 should be applied prospectively to loans that are acquired on or after adoption date and are effective for annual and interim periods beginning after December 15, 2026, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU 2025-08 on its consolidated financial statements and related disclosures.

ASU 2025-09 – In November 2025, the FASB issued ASU No. 2025-09, Derivatives and Hedging (Topic 815) — Hedge Accounting Improvements, or ASU 2025-09. The update more closely aligns hedge accounting with the economics of an entity’s risk management activities. The amendments of ASU 2025-09 should be applied prospectively to all hedging relationships and are effective for annual and interim periods beginning after December 15, 2026, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU 2025-09 on its consolidated financial statements and related disclosures.

ASU 2025-10 – In December 2025, the FASB issued ASU No. 2025-10, Government Grants (Topic 832) — Accounting for Government Grants Received by Business Entities, or ASU 2025-10. The update provides authoritative guidance on the accounting for government grants received by an entity. This ASU is effective for annual and interim reporting periods beginning after December 15, 2028, with early adoption permitted. The amendments may be applied either (1) using a modified prospective basis for all grants entered into on, after, or not complete as of the adoption date, (2) modified retrospective basis for all grants entered on, after, or not complete as of the earliest period presented, or (3) retrospectively to all prior periods presented in the financial statements. The Company is currently evaluating the impact of adopting ASU 2025-10 on its consolidated financial statements and related disclosures.

ASU 2025-11 – In December 2025, the FASB issued ASU No. 2025-11, Interim Reporting (Topic 270) — Narrow-Scope Improvements, or ASU 2025-11. This ASU clarifies interim reporting by aggregating interim disclosures required throughout the various Codification topics into Topic 270 and requiring entities to produce interim disclosures when a material event or change has occurred since the prior year-end. This ASU is effective for interim periods beginning after December 15, 2027, with early adoption permitted. The amendments in this ASU may be applied either (1) prospectively or (2) retrospectively to any or all prior periods presented in the financial statements. The Company is currently evaluating the impact of adopting ASU 2025-11 on its disclosures.

Note 3 — Revenue Recognition

Performance Obligations

As of March 31, 2026, estimated future fixed fee performance obligations are $2.0 billion for the remaining nine months of fiscal year 2026, and $2.6 billion, $1.8 billion, $1.1 billion, $744 million and $8 million for the fiscal years 2027, 2028, 2029, 2030 and 2031, 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 and demand response. The cleared auction MWs are subject to penalties for non-performance. The increase in future fixed fee performance obligations as of March 31, 2026, compared to the same period in 2025 is primarily due to the acquisition of the LSP Portfolio.

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three months ended March 31, 2026 and 2025:


	Three months ended March 31, 2026
(In millions)	Texas(a)		East(a)		West/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home	$	1,449	$	775	$	342	$	578	$	(12)	$	3,132
Business	886		4,962		520		—		—		6,368
Total retail revenue(b)	2,335		5,737		862		578		(12)		9,500
Energy revenue(b)	8		467		—		—		—		475
Capacity revenue(b)	—		239		—		—		—		239
Mark-to-market for economic hedging activities(c)	—		(44)		—		—		2		(42)
Contract amortization	—		6		—		—		—		6
Other revenue(b)	50		27		2		—		(1)		78
Total revenue	2,393		6,432		864		578		(11)		10,256
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		46		2		47		—		95
Less: Realized and unrealized ASC 815 revenue	(3)		29		(3)		—		2		25
Total revenue from contracts with customers	$	2,396	$	6,357	$	865	$	531	$	(13)	$	10,136
(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	41	$	—	$	—	$	—	$	41
Energy revenue	—		5		—		—		—		5
Capacity revenue	—		26		—		—		—		26
Other revenue	(3)		1		(3)		—		—		(5)
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Three months ended March 31, 2025
(In millions)	Texas		East		West/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home	$	1,555	$	738	$	460	$	511	$	(4)	$	3,260
Business	832		3,612		512		—		—		4,956
Total retail revenue(a)	2,387		4,350		972		511		(4)		8,216
Energy revenue(a)	7		158		81		—		(1)		245
Capacity revenue(a)	—		40		8		—		(1)		47
Mark-to-market for economic hedging activities(b)	—		(19)		2		—		2		(15)
Contract amortization	—		(5)		—		—		—		(5)
Other revenue(a)	41		53		7		—		(4)		97
Total revenue	2,435		4,577		1,070		511		(8)		8,585
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		37		2		26		—		65
Less: Realized and unrealized ASC 815 revenue	(2)		26		6		—		1		31
Total revenue from contracts with customers	$	2,437	$	4,514	$	1,062	$	485	$	(9)	$	8,489
(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/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	11	$	—	$	—	$	—	$	11
Energy revenue	—		14		4		—		—		18
Capacity revenue	—		16		—		—		—		16
Other revenue	(2)		4		—		—		(1)		1
(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 March 31, 2026 and December 31, 2025:


(In millions)	March 31, 2026		December 31, 2025
Capitalized contract costs (included in Prepayments and other current assets and Other non-current assets)	$	1,731	$	1,680

Accounts receivable, net - Contracts with customers	3,673		3,924
Accounts receivable, net - Accounted for under topics other than ASC 606	96		135
Accounts receivable, net - Affiliate	8		6
Total accounts receivable, net	$	3,777	$	4,065

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,439	$	1,747
Deferred revenues(a)	1,595		1,643

(a)Deferred revenues recognized under accounting guidance other than ASC 606 was immaterial as of both March 31, 2026 and December 31, 2025

The revenue recognized from contracts with customers during the three months ended March 31, 2026 and 2025 relating to the deferred revenue balance at the beginning of each period was $344 million and $270 million, respectively, which increased primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.

Note 4 — Acquisitions

2026 Acquisition

Acquisition of LSP Portfolio

On January 30, 2026, NRG completed the acquisition of the LSP Portfolio from LS Power, pursuant to the Purchase Agreement dated as of May 12, 2025. The acquisition doubles NRG’s generation capacity with the addition of 18 natural gas-fired and dual fuel facilities totaling approximately 13 GW. These facilities, located across nine states, expand NRG’s generation footprint in the Northeast and Texas, where most of its load is located. In addition, NRG acquired CPower, a leading demand response platform, which operates in all the country’s deregulated energy markets and has more than 2,000 commercial and industrial customers.

The consideration consisted of 24.25 million shares of NRG common stock and $6.4 billion in cash, plus preliminary working capital and certain other adjustments of $483 million. The Company funded the cash consideration using a portion of the net proceeds from the 5.750% 2034 Senior Notes, the 2036 Senior Notes, Senior Secured First Lien Notes, due 2030 and the Senior Secured First Lien Notes, due 2035 of $4.4 billion and proceeds of $2.5 billion from the Company’s Revolving Credit Facility.

The total preliminary consideration of $10.583 billion was calculated as follows:


	(In millions)
Cash consideration (inclusive of preliminary working capital and certain other adjustments of $483 million)	$	6,855
Stock consideration: 24,250,000 common shares of NRG, par value $0.01 per share, based on NRG closing share price of $153.72 on January 29, 2026	3,728
Total Preliminary Consideration	$	10,583

Acquisition costs of $38 million for the three months ended March 31, 2026 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)
Current Assets
Cash and cash equivalents	$	104

Restricted cash	2
Accounts receivable, net	587
Inventory	175
Derivative instruments	715
Cash collateral paid in support of energy risk management activities	184
Prepayments and other current assets	123
Total current assets	1,890
Property, plant and equipment, net	9,684
Other Assets
Operating lease right-of-use assets, net	25
Goodwill(a)(b)	3,866
Customer relationships, net(b)	130
Other intangible assets, net(b)	87
Derivative instruments	335
Deferred income taxes	31
Other non-current assets	32
Total other assets	4,506
Total Assets	$	16,080

Current Liabilities
Current portion of long-term debt and finance leases	$	18
Current portion of operating lease liabilities	1
Accounts payable	595
Derivative instruments	784
Deferred revenue current	6
Accrued expenses and other current liabilities	171
Total current liabilities	1,575
Other Liabilities
Long-term debt and finance leases	3,311
Non-current operating lease liabilities	24
Derivatives instruments	362
Deferred income taxes	116

Other non-current liabilities	109
Total other liabilities	3,922
Total Liabilities	$	5,497

LSP Portfolio Purchase Price	$	10,583

(a)Goodwill arising from the acquisition of $3.866 billion is attributed to the value of the platform acquired, future customer growth and the expected benefits from combining the operations of the LSP Portfolio with NRG's existing businesses, a majority of which is expected to be deductible for tax purposes. Goodwill was preliminarily allocated to the Texas and East segments of $1.591 billion and $2.275 billion, respectively

(b)The allocation of goodwill and intangible assets to the Company’s reportable segments is anticipated to be finalized by the end of 2026

Fair Value Measurement of Property, Plant and Equipment

The fair values of the property, plant and equipment were measured using income-based valuation methodologies, which included certain assumptions, such as forecasted future cash flows, discount rates, market prices and asset lives and are classified as Level 3. Property, plant and equipment are depreciated to depreciation and amortization, on a straight-line basis, over the expected useful lives of the assets.

Fair Value Measurement of Intangible Assets

The fair values of intangible assets as of the acquisition closing date were measured as follows:

Customer relationships – Customer relationships, reflective of the LSP Portfolio’s customer base, were valued using an excess earning method of the income approach, and is classified as Level 3. Under this approach, the Company estimated the present value of expected future cash flows resulting from existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce, trade names and technology) utilized in the business, discounted based on the required rate of return on the acquired intangible asset. The customer relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows.

Technology – Developed technology was valued using a relief from royalty method of the income approach, and is classified as Level 3. Under this approach, the fair value was estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount that would be paid by a hypothetical market participant had they not owned the asset and instead licensed the asset from another company. The estimated cash flows from the developed technology considered the obsolescence factor and was discounted using a weighted average cost of capital of comparable companies. The developed technology is amortized to depreciation and amortization, ratably based on discounted future cash flows.

Trade name — Trade name was valued using a relief from royalty method of the income approach, and is classified as Level 3. Under this approach, the fair value is estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount that would be paid by a hypothetical market participant had they not owned the asset and instead licensed the asset from another company. The estimated cash flows from the trade name considered the expected probable use of the asset and was discounted using a weighted average cost of capital of comparable companies. The trade name is amortized to depreciation and amortization, on a straight line basis, over the expected life of the asset.

Fair Value Measurement of LS Power Debt

The Company acquired $3.2 billion in aggregate principal of LS Power’s 7.250% Senior Secured Notes due 2032, Lightning Term Loan and Lightning Revolving Facility (together, the "Acquired LS Power Debt") which were recorded at fair value as of the acquisition closing date. The difference between the fair value at the acquisition closing date and the principal outstanding of the Acquired LS Power Debt, of $100 million, is being amortized through interest expense over the remaining term of the debt. The 7.250% Senior Secured Notes due 2032 and Lightning Term Loan are classified as Level 2 and were measured at fair value using observable market inputs based on interest rates at the acquisition closing date. For additional discussion, see Note 7, Long-term Debt and Finance Leases.

Fair Value Measurement of Derivatives Instruments

The fair values of derivatives instruments outstanding as of the acquisition closing date were valued using a discounted cash flow approach, with inputs consisting of available market data, such as consensus pricing, as well as unobservable internally derived assumptions, such as forward market prices and auction prices. These derivatives are classified as Level 1, Level 2 and Level 3 and changes to the fair value are recorded through revenue and cost of operations in the consolidated statement of operations. For additional discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities.

Supplemental Information

The Company recorded revenue from the LSP Portfolio of $481 million and income before tax of $3 million during the three months ended March 31, 2026. The revenue reported does not include the effects of hedging, which are managed at the Company’s portfolio level and not separately for the business acquired in the LSP Portfolio acquisition.

Supplemental Pro Forma Financial Information for the three months ended March 31, 2026 and 2025

The following table provides pro forma combined financial information of NRG and LSP Portfolio, after giving effect to the LSP Portfolio acquisition and related financing transactions as if they had occurred on January 1, 2025. The pro forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project future operating results or be indicative of what the Company's financial performance would have been had the transactions occurred on the date acquired.


(In millions)	Three months ended March 31, 2026		Three months ended March 31, 2025
Revenue	$	10,885	$	9,069
Net income	278		611

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

(i)Elimination of transactions between NRG and LS Power acquired entities.

(ii)Adjustments to align the capitalization of certain maintenance costs.

(iii)Adjustments to align classification of certain historical revenue with the Company’s policy.

(iv)Income statement effects of fair value adjustments based on the preliminary purchase price allocation including depreciation of property, plant and equipment, amortization of intangible assets and adjustment to interest expense as a result of recording assumed debt at acquisition date fair value.

(v)Adjustments to record expected acquisition costs.

(vi)Interest expense assumes the financing transactions directly attributable to the LSP Portfolio acquisition occurred on January 1, 2025.

(vii)Adjustments to remove the impact of unassumed debt.

(viii)Income tax effect of the acquisition accounting adjustments and financing adjustments based on combined blended federal/state tax rate of 24.83% for all periods presented, and the impact of a one time benefit resulting from the acquisition.

2025 Acquisition

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. For additional information, refer to Note 4, Acquisitions and Dispositions, to the Company’s 2025 Form 10-K.

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:


	March 31, 2026				December 31, 2025
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value







Total long-term debt, including current portion(a)	$	23,269	$	22,948	$	16,565	$	16,405

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

The fair value of the Company’s publicly-traded long-term debt, the Term Loan B and the Lightning Term Loan 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, the Cedar Bayou 5 TEF loan and the Greens Bayou 6 TEF loan are determined using discounted cash flow methodologies, and are classified as Level 3 within the fair value hierarchy. The estimated fair value of the borrowings under the Revolving Credit Facility and the Receivables Facility approximate the carrying value because the interest rates vary with market interest rates, 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 March 31, 2026 and December 31, 2025:


	March 31, 2026				December 31, 2025
(In millions)	Level 2		Level 3		Level 2		Level 3



Total long-term debt, including current portion	$	19,213	$	3,735	$	16,033	$	372

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:


	March 31, 2026
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	34	$	—	$	34	$	—



Derivative assets:
Interest rate contracts	3		—		3		—
Foreign exchange contracts	7		—		7		—
Commodity contracts(a)	4,210		333		3,593		284


Equity securities measured using net asset value practical expedient (classified within other non-current assets)	6
Total assets	$	4,260	$	333	$	3,637	$	284
Derivative liabilities:
Interest rate contracts	$	1	$	—	$	1	$	—
Foreign exchange contracts	1		—		1		—
Commodity contracts(a)	4,305		453		3,598		254
Consumer Financing Program	252		—		—		252
Total liabilities	$	4,559	$	453	$	3,600	$	506

(a)Excludes $565 million of derivative assets and $132 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


	December 31, 2025
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	33	$	—	$	33	$	—


Derivative assets:

Foreign exchange contracts	3		—		3		—
Commodity contracts(a)	3,132		267		2,552		313



Equity securities measured using net asset value practical expedient (classified within other non-current assets)	7
Total assets	$	3,175	$	267	$	2,588	$	313
Derivative liabilities:
Interest rate contracts	$	4	$	—	$	4	$	—
Foreign exchange contracts	3		—		3		—
Commodity contracts(a)	2,932		352		2,377		203
Consumer Financing Program	283		—		—		283
Total liabilities	$	3,222	$	352	$	2,384	$	486

(a)Excludes $622 million of derivative assets and $138 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

The following table reconciles, for the three months ended March 31, 2026 and 2025, 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 March 31, 2026		Three months ended March 31, 2025
Beginning balance	$	110	$	39
Contracts added from LSP Portfolio acquisition	5		—
Total (losses)/gains realized/unrealized included in earnings	(102)		12
Purchases	12		—
Transfers into Level 3(b)	1		—
Transfers out of Level 3(b)	4		(2)
Ending balance	$	30	$	49
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end	$	(73)	$	42

(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 months ended March 31, 2026 and 2025, 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 March 31, 2026		Three months ended March 31, 2025
Beginning balance	$	(283)	$	(203)

New contractual obligations	(26)		(32)
Settlements	60		36
Total losses included in earnings	(3)		(8)
Ending balance	$	(252)	$	(207)

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 March 31, 2026, contracts valued with prices provided by models and other valuation techniques made up 7% of derivative assets and 11% 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 March 31, 2026 and December 31, 2025:



	March 31, 2026
	Fair Value						Input/Range
(In millions, except as noted)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	$	54	$	24	Discounted Cash Flow	Forward Market Price ($ per MMBtu)	$	1		$	21		$	5
Power Contracts	155		114		Discounted Cash Flow	Forward Market Price ($ per MWh)	1			244			28
Capacity Contracts	25		34		Discounted Cash Flow	Forward Market Price ($ per MW/Day)	53			806			328
RECs	10		38		Discounted Cash Flow	Forward Market Price ($ per Certificate)	2			375			16
FTRs	23		14		Discounted Cash Flow	Auction Prices ($ per MWh)	(47)			19,100			0
Power Options	17		30		Option Models	Volatilities	27		%	335		%	110		%
Consumer Financing Program	—		252		Discounted Cash Flow	Collateral Default Rates	0.89		%	44.20		%	7.97		%
					Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.51		%
					Discounted Cash Flow	Credit Loss Rates	6.53		%	60.00		%	17.20		%
	$	284	$	506



	December 31, 2025
	Fair Value						Input/Range
(In millions, except as noted)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	$	47	$	40	Discounted Cash Flow	Forward Market Price ($ per MMBtu)	$	—		$	17		$	5
Power Contracts	168		64		Discounted Cash Flow	Forward Market Price ($ per MWh)	0			125			29
Capacity Contracts	20		18		Discounted Cash Flow	Forward Market Price ($ per MW/Day)	49			577			270
RECs	12		25		Discounted Cash Flow	Forward Market Price ($ per Certificate)	2			370			17
FTRs	22		11		Discounted Cash Flow	Auction Prices ($ per MWh)	(50)			19,100			0
Power Options	44		45		Option Models	Volatilities	22		%	517		%	110		%
Consumer Financing Program	—		283		Discounted Cash Flow	Collateral Default Rates	1.18		%	42.00		%	7.86		%
					Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.52		%
					Discounted Cash Flow	Credit Loss Rates	6.40		%	60.00		%	16.94		%
	$	313	$	486

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant, unobservable inputs as of March 31, 2026 and December 31, 2025:

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 March 31, 2026, the credit reserve resulted in a $2 million increase in fair value, primarily within cost of operations. As of December 31, 2025, the credit reserve was immaterial.

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 2025 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 2025 Form 10-K. As of March 31, 2026, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $1.3 billion and NRG held collateral (cash and letters of credit) against those positions of $117 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 61% of the Company’s exposure before collateral is expected to roll off by the end of 2027. 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	73	%
Financial institutions	27

Total as of March 31, 2026	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	70	%
Non-investment grade/Non-Rated	30
Total as of March 31, 2026	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 March 31, 2026. 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 March 31, 2026, aggregate credit risk exposure managed by NRG to these counterparties was approximately $679 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 March 31, 2026, 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 March 31, 2026, 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.

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 March 31, 2026, 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 February 2026, the Company entered into treasury locks with a total notional amount of $800 million which were fully terminated in March 2026.

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 March 31, 2026, 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 March 31, 2026 and December 31, 2025. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.


		Total Volume (In millions)
Category	Units	March 31, 2026	December 31, 2025
Emissions	Short Ton	4	2
Renewable Energy Certificates	Certificates	13	13
Coal	Short Ton	7	8
Natural Gas	MMBtu	1,221	907

Power	MWh	65	103
Interest	Dollars	700	700
Foreign Exchange	Dollars	397	437
Consumer Financing Program	Dollars	1,254	1,354

Fair Value of Derivative Instruments

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


	Fair Value
	Derivative Assets				Derivative Liabilities
(In millions)	March 31, 2026		December 31, 2025		March 31, 2026		December 31, 2025




Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts - current	$	—	$	—	$	1	$	4
Interest rate contracts - long-term	3		—		—		—
Foreign exchange contracts - current	5		2		—		1
Foreign exchange contracts - long-term	2		1		1		2
Commodity contracts - current	2,883		1,991		3,004		1,997
Commodity contracts - long-term	1,327		1,141		1,301		935
Consumer Financing Program - current	—		—		164		184
Consumer Financing Program - long-term	—		—		88		99
Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	4,220	$	3,135	$	4,559	$	3,222
Deferred gains/losses on NPNS contracts - current	193		196		61		71
Deferred gains/losses on NPNS contracts - long-term	372		426		71		67
Deferred gains/losses on NPNS contracts(a)	$	565	$	622	$	132	$	138
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	4,785	$	3,757	$	4,691	$	3,360

(a)Balances related to certain derivative contracts that were accounted for as derivative contracts prior to the election of the NPNS exemption on October 1, 2024 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 March 31, 2026
Interest rate contracts:
Derivative assets	$	3	$	(1)	$	—	$	2
Derivative liabilities	(1)		1		—		—
Total interest rate contracts	$	2	$	—	$	—	$	2
Foreign exchange contracts:
Derivative assets	$	7	$	(1)	$	—	$	6
Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	$	6	$	—	$	—	$	6
Commodity contracts:
Derivative assets	$	4,775	$	(3,662)	$	(162)	$	951
Derivative liabilities	(4,437)		3,662		316		(459)
Total commodity contracts	$	338	$	—	$	154	$	492
Consumer Financing Program:
Derivative liabilities	$	(252)	$	—	$	—	$	(252)
Total derivative instruments	$	94	$	—	$	154	$	248


	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, 2025
Interest rate contracts:

Derivative liabilities	$	(4)	$	—	$	—	$	(4)

Foreign exchange contracts:
Derivative assets	$	3	$	(2)	$	—	$	1
Derivative liabilities	(3)		2		—		(1)
Total foreign exchange contracts	$	—	$	—	$	—	$	—
Commodity contracts:
Derivative assets	$	3,754	$	(2,724)	$	(215)	$	815
Derivative liabilities	(3,070)		2,724		137		(209)
Total commodity contracts	$	684	$	—	$	(78)	$	606
Consumer Financing Program:
Derivative liabilities	$	(283)	$	—	$	—	$	(283)


Total derivative instruments	$	397	$	—	$	(78)	$	319

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 March 31,
Unrealized mark-to-market results	2026		2025
Reversal of previously recognized unrealized gains on settled positions related to economic hedges(a)	$	(34)	$	(218)
Reversal of acquired loss/(gain) positions related to economic hedges	10		(4)
Net unrealized (losses)/gains on open positions related to economic hedges	(181)		553
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(205)		331
Reversal of previously recognized unrealized gains on settled positions related to trading activity	—		(1)

Net unrealized losses on open positions related to trading activity	(7)		(3)
Total unrealized mark-to-market losses for trading activity	(7)		(4)
Total unrealized (losses)/gains - commodities and foreign exchange	$	(212)	$	327

(a)For the three months ended March 31, 2026 and 2025, includes $(51) million and $(83) 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 March 31,
(In millions)	2026		2025
Total impact to statement of operations - interest rate contracts	$	6	$	(9)
Unrealized losses included in revenues - commodities	$	(49)	$	(19)
Unrealized (losses)/gains included in cost of operations - commodities	(168)		350
Unrealized gains/(losses) included in cost of operations - foreign exchange	5		(4)
Total impact to statement of operations - commodities and foreign exchange	$	(212)	$	327
Total impact to statement of operations - Consumer Financing Program	$	(3)	$	(8)

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

For the three months ended March 31, 2026, the $181 million unrealized loss from open economic hedge positions was primarily the result of a decrease in the value of forward positions as a result of decreases in natural gas prices and CAISO and Alberta power prices.

For the three months ended March 31, 2025, the $553 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 natural gas prices and ERCOT and East 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 March 31, 2026 was $694 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 $238 million as of March 31, 2026. In the event of a downgrade in the Company’s credit rating and if called for by the counterparty, $61 million of additional collateral would be required for all contracts with credit rating contingent features as of March 31, 2026.

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)	March 31, 2026		December 31, 2025		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
Senior Notes, due 2034	1,250		1,250		5.750
Senior Notes, due 2036	2,400		2,400		6.000


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 2030	625		625		4.734
Senior Secured First Lien Notes, due 2033	740		740		7.000
Senior Secured First Lien Notes, due 2035	625		625		5.407
Receivables Facility, due 2026	350		—		SOFR + 0.775
Revolving Credit Facility	2,975		—		SOFR + 1.720
Term Loan B, due 2031	2,293		2,299		SOFR + 1.750
Tax-exempt bonds	466		466		4.000 - 4.750
T.H. Wharton TEF loan, due 2045	194		189		3.000
Cedar Bayou 5 TEF loan, due 2045	290		255		3.000
Greens Bayou 6 TEF loan, due 2045	112		90		3.000
Subtotal recourse debt	19,957		16,576
Non-recourse debt:

Lightning Term Loan, due 2031	1,724		—		SOFR + 2.250
Lightning Senior Secured Notes, due 2032	1,500		—		7.250
Subtotal all Lightning non-recourse debt	3,224		—
Subtotal long-term debt (including current maturities)	23,181		16,576
Finance leases	29		24		various
Subtotal long-term debt and finance leases (including current maturities)	23,210		16,600
Less current maturities	(3,375)		(31)
Less debt issuance costs	(144)		(146)
Premiums/(discounts), net	88		(11)
Total long-term debt and finance leases	$	19,779	$	16,412

Recourse Debt

Term Loan B Incurrence

On April 28, 2026, the Company and APX Group LLC, as borrowers, and certain of the Company’s subsidiaries, as guarantors, entered into the Sixteenth Amendment to the Second Amended and Restated Credit Agreement (the “Sixteenth Amendment”), dated of June 30, 2016, with, among others, Citicorp North America, Inc., as administrative agent and as collateral agent, and certain financial institutions, as lenders (as amended, restated, supplemented and/or otherwise modified from time to time, the “Credit Agreement”), in order to (i) establish new term loans in aggregate principal amount of $900 million (the “Incremental Term Loans”), and (ii) make certain modifications to the Credit Agreement in connection therewith. The Incremental Term Loans constitute a new and separate class of term loans under the Credit Agreement.

Issuance of Unsecured Notes and Secured Notes

On April 28, 2026, the Company issued $2.1 billion in aggregate principal amount of senior unsecured notes consisting of (i) $1.05 billion aggregate principal amount of 5.875% senior notes due 2034 (the “New 2034 Notes”) and (ii) $1.05 billion aggregate principal amount of 6.125% senior notes due 2036 (the “New 2036 Notes” and, together with the New 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 loans under the Senior Credit Facility. The New 2034 Notes will mature on May 15, 2034. Interest on the New 2034 Notes will be paid semi-annually on May 15 and November 15 of each year commencing on November 15, 2026. The New 2036 Notes will mature on May 15, 2036. Interest on the New 2036 Notes will be paid semi-annually commencing on November 15, 2026.

On April 28, 2026, the Company also issued $500 million aggregate principal amount of 4.955% senior secured first lien notes due 2031 (the “New 2031 Notes”). The New 2031 Notes are senior secured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the loans under the Senior Credit Facility. The New 2031 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 and existing senior secured notes, which collateral consists of a substantial portion of the property and assets owned by the Company and the guarantors. The New 2031 Notes will mature on April 30, 2031. Interest on the New 2031 Notes will be paid semi-annually on April 30 and October 30 of each year commencing on October 30, 2026.

The Company used the net proceeds from the New Unsecured Notes, together with the net proceeds from the New 2031 Notes, and the Incremental Term Loans, to pay the tender price of the Tender Offer (as defined below), to pay estimated transaction fees, expenses and premiums, and the remainder to repay a portion of the outstanding borrowings under the Company’s Revolving Credit Facility.

Bilateral Letter of Credit Facilities

In January and February 2026, the Company and certain of its subsidiaries, as guarantors, entered into amendments to its existing bilateral letter of credit facilities to increase the size of its bilateral credit facilities by $410 million and $90 million, respectively, to provide additional liquidity. As of March 31, 2026, $739 million was issued under these facilities.

Texas Development Projects

As of April 30, 2026, $192 million, $302 million and $117 million of disbursements have occurred for the T.H. Wharton TEF loan, due 2045, Cedar Bayou 5 TEF loan, due 2045 and Greens Bayou 6 TEF loan, due 2045, respectively (collectively the “TEF loans”).

Non-recourse Debt

The following are descriptions of certain indebtedness of NRG’s subsidiaries, which are non-recourse debt to NRG.

Acquired LS Power Debt

On January 30, 2026 (the “Acquisition Closing Date”), in connection with the acquisition of the LSP Portfolio from LS Power, Lightning, an indirect, wholly-owned subsidiary of NRG as of such date, retained its 7.250% Senior Secured Notes due 2032, term loan and revolving loan facility.

Lightning Notes

On the Acquisition Closing Date, Lightning remained the issuer of $1.5 billion aggregate principal amount of 7.250% Senior Secured Notes due 2032 (the “Lightning 2032 Notes”) issued pursuant to an indenture dated August 16, 2024 (the “Lightning Indenture”), by and among Lightning, Lightning’s subsidiaries that are guarantors from time to time party thereto, and U.S. Bank Trust Company, National Association, in its capacities as trustee and collateral trustee (the “Lightning Notes Trustee”).

Subject to certain qualifications and exceptions, the Lightning Indenture, among other things, limits Lightning’s ability and the ability of Lightning’s restricted subsidiaries to incur or guarantee additional indebtedness; create or incur liens; make certain restricted payments; and consolidate, merge or transfer all or substantially all of Lightning’s and its subsidiaries’ assets on a consolidated basis.

Lightning Tender Offer and Redemption

On April 14, 2026, Lightning commenced a cash tender offer to purchase any and all of the Lightning 2032 Notes (the “Tender Offer”). In conjunction with the Tender Offer, Lightning solicited consents (the “Consent Solicitation”) to adopt certain proposed amendments to the Lightning Indenture to (1) eliminate substantially all of the restrictive covenants and certain affirmative covenants and events of default and related provisions therein and (2) release all of the guarantees of and the collateral securing the Lightning 2032 Notes.

As of the early tender deadline for the Tender Offer on April 27, 2026, $1.495 billion aggregate principal amount of Lightning 2032 Notes (or 99.670%) were tendered. On April 29, 2026, Lightning repurchased such tendered notes for an aggregate purchase price of $1.59 billion (plus accrued and unpaid interest to, but excluding, the repurchase date). In addition, pursuant to the Consent Solicitation, Lightning obtained consents from the requisite holders of the Lightning 2032 Notes and, on April 29, 2026, Lightning, the Lightning Notes Trustee, and the relevant guarantors, entered into a supplemental indenture to the Lightning Indenture to effectuate the amendments described above. The Tender Offer is scheduled to expire on May 12, 2026.

Further, pursuant to the terms of the Lightning Indenture, on April 28, 2026, Lightning issued a notice of redemption to redeem (the “Redemption”) the remaining $5 million aggregate principal amount of the Lightning 2032 Notes at a redemption price of 101.375% (plus accrued and unpaid interest to, but excluding, the redemption date). The redemption of such notes is scheduled to occur on May 14, 2026.

Lightning Credit Facility

On the Acquisition Closing Date, Lightning remained party to a credit agreement (the “Lightning Credit Agreement”) with Morgan Stanley Senior Funding, Inc. as administrative agent and collateral agent and various lenders and issuing banks from time to time party thereto. The Lightning Credit Agreement consists of a term loan in an original aggregate principal amount of $1.75 billion (the “Lightning Term Loan”) and revolving loan facility of $600 million (the “Lightning Revolving Facility”). The maturity date of the Lightning Term Loan and the Lightning Revolving Facility is August 16, 2031, and August 16, 2029, respectively. Interest on the Lightning Term Loan accrues at a rate per annum equal to the SOFR rate plus a margin of 2.250%, subject to leverage-based margin step-downs. Interest on revolving credit borrowings under the Lightning Revolving Facility accrues at a rate per annum equal to the SOFR rate plus a margin of 2.000%, subject to leverage-based margin step-downs. As of March 31, 2026, there were no outstanding borrowings and there were $105 million in letters of credit issued under the Lightning Revolving Facility.

Note 8 — Investments Accounted for by the Equity Method and Variable Interest Entities

Entities that are not Consolidated

NRG accounts for the Company’s 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 2025 Form 10-K.

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


(In millions)	March 31, 2026		December 31, 2025
Accounts receivable, net and Other current assets	$	2,466	$	2,779




Current liabilities	506		155







Net assets	$	1,960	$	2,624

Note 9 — Changes in Capital Structure

As of March 31, 2026 and December 31, 2025, 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, 2025	650,000	199,828,615	(9,452,008)	190,376,607
Shares issued under LTIPs	—	1,112,449	—	1,112,449


Shares repurchased	—	—	(2,976,169)	(2,976,169)

Shares issued for the acquisition of the LSP Portfolio	—	24,250,000	—	24,250,000
Retirement of treasury stock	—	(340,900)	340,900	—
Balance as of March 31, 2026	650,000	224,850,164	(12,087,277)	212,762,887
Shares issued under LTIPs	—	296,220	—	296,220
Shares issued under ESPP	—	—	85,289	85,289
Shares repurchased	—	—	(2,157,926)	(2,157,926)



Balance as of April 30, 2026	650,000	225,146,384	(14,159,914)	210,986,470

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. During the quarter ended March 31, 2026, the Company completed repurchases under its $3.7 billion share repurchase program, which began in 2023. The remaining repurchases were made under the October 16, 2025 Board of Directors’ authorization of share repurchases 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 which was completed during the quarter ended March 31, 2026:


	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	9,971,620	$	130.58	1,302
Shares received from the exercise of the Capped Call Options	224,585	$	69.38	16		(d)
Total Share Repurchases during 2025	10,196,205			$	1,318	(e)
2026 Repurchases:
Open market repurchases	1,146,900	$	156.62	180
Shares repurchased from LS Power	771,080	$	164.00	127		(f)
Total Share Repurchases during 2026 under the $3.7 billion authorization	1,917,980			$	307	(g)
Total Share Repurchases under the $3.7 billion authorization	46,570,688	$	79.43	$	3,700

(a)Under the November 6, 2023 accelerated share repurchase agreements, 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. For additional information, refer to Note 15, Capital Structure, to the Company’s 2025 Form 10-K

(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)For further information on the Capped Call Options, see discussion below

(e)Excludes $11 million of excise tax accrued in 2025

(f)The Company entered into a stock purchase agreement to repurchase 1,829,269 shares of NRG common stock from LS Power. 771,080 shares were repurchased under the $3.7 billion authorization, and the remaining 1,058,189 shares were repurchased under the $3.0 billion authorization

(g)Excludes $3 million accrued for estimated excise tax for the three months ended March 31, 2026

The following table summarizes the share repurchases made under the $3.0 billion authorization through April 30, 2026:


	Total number of shares purchased	Average price paid per share		Amounts paid for shares purchased (in millions)
2026 Repurchases:
Shares repurchased from LS Power(a)	1,058,189	$	164.00	$	174
Open market repurchases April 1, 2026 through April 30, 2026	2,157,926	$	156.52	338
Total Share Repurchases under the $3.0 billion authorization	3,216,115	$	158.98	$	512

(a)The Company entered into a stock purchase agreement to repurchase 1,829,269 shares of NRG common stock from LS Power. 771,080 shares were repurchased under the $3.7 billion authorization, and the remaining 1,058,189 shares were repurchased under the $3.0 billion authorization

Employee Stock Purchase Plan

The Company offers participation in the ESPP which allows eligible employees to elect to withhold between 1% and 100%, 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 2026, NRG increased the annual dividend to $1.90 from $1.76 per share. A quarterly dividend of $0.475 per share was paid on the Company’s common stock during the three months ended March 31, 2026. On April 21, 2026, NRG declared a quarterly dividend on the Company’s common stock of $0.475 per share, payable on May 15, 2026 to stockholders of record as of May 1, 2026. 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 three months ended March 31, 2026 and 2025, the Company retired shares of treasury stock as detailed below. These retired shares are now included in NRG’s pool of authorized but unissued shares. The Company’s accounting policy upon the formal retirement of treasury stock is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from additional paid-in-capital.


	Total number of treasury shares retired	Average price per share		Carrying value of treasury shares retired (in millions)

Shares retired during the first quarter of 2026	340,900	$	116.00	$	40




Shares retired during the first quarter of 2025	3,070,996	$	58.23	$	179

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 mitigate the impact of potential dilution of the Convertible Senior Notes. 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 March 31, 2026. 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 March 31, 2026 and 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 Per Share

Basic income per common share is computed by dividing net income 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 per share is computed in a manner consistent with that of basic income per share while giving effect to all potentially dilutive common shares that were outstanding during the period 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 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 months ended March 31, 2025, the Convertible Senior Notes were convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock. The Company included the potential share settlements, if any, in the denominator for purposes of computing diluted income per share under the if converted method. 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. The Company settled all of the outstanding Convertible Senior Notes as of July 8, 2025.

NRG’s basic and diluted income per share is shown in the following table:


	Three months ended March 31,
(In millions, except per share data)	2026		2025
Basic income per share:
Net income	$	125	$	750
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17
Net income available for common stockholders	$	108	$	733
Weighted average number of common shares outstanding - basic	207		198
Income per weighted average common share — basic	$	0.52	$	3.70

Diluted income per share:
Net income	$	125	$	750
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17
Net income available for common stockholders	$	108	$	733
Weighted average number of common shares outstanding - basic	207		198
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	1		2
Incremental shares attributable to the potential share settlements of the Convertible Senior Notes (if converted method)	—		3
Weighted average number of common shares outstanding - dilutive	208		203
Income per weighted average common share — diluted	$	0.52	$	3.61

For the three months ended March 31, 2026 and 2025, 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. 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 2025 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 March 31, 2026
(In millions)	Texas(a)		East(a)		West/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue(b)	$	2,393	$	6,432	$	864	$	578	$	—	$	(11)	$	10,256
Operating expenses	2,256		6,092		809		300		50		(11)		9,496
Depreciation and amortization	108		102		8		200		14		—		432

Total operating cost and expenses	2,364		6,194		817		500		64		(11)		9,928

Operating income/(loss)	29		238		47		78		(64)		—		328


Other income, net	—		—		(2)		(3)		45		—		40

Interest expense	—		—		—		—		(285)		—		(285)
Income/(loss) before income taxes	29		238		45		75		(304)		—		83
Income tax benefit	—		—		—		—		(42)		—		(42)
Net income/(loss)	$	29	$	238	$	45	$	75	$	(262)	$	—	$	125






(a) Includes result of operations following the acquisition date of the LSP Portfolio of January 30, 2026
(b) Inter-segment sales and inter-segment net derivative gains and losses included in revenues	$	12	$	(2)	$	1	$	—	$	—	$	—	$	11

Other segment information
Capital expenditures	$	256	$	23	$	3	$	2	$	33	$	—	$	317


	Three months ended March 31, 2025
(In millions)	Texas		East		West/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue(a)	$	2,435	$	4,577	$	1,070	$	511	$	—	$	(8)	$	8,585
Operating expenses	2,015		3,839		990		263		19		(8)		7,118
Depreciation and amortization	83		37		9		186		11		—		326

Total operating cost and expenses	2,098		3,876		999		449		30		(8)		7,444
Loss on sale of assets	—		—		(7)		—		—		—		(7)
Operating income/(loss)	337		701		64		62		(30)		—		1,134

Other income, net	—		4		2		(8)		16		—		14

Interest expense	—		—		—		—		(163)		—		(163)
Income/(loss) before income taxes	337		705		66		54		(177)		—		985
Income tax expense	—		—		—		—		235		—		235
Net income/(loss)	$	337	$	705	$	66	$	54	$	(412)	$	—	$	750
(a) Inter-segment sales and inter-segment net derivative gains and losses included in revenues	$	7	$	(1)	$	2	$	—	$	—	$	—	$	8

Other segment information
Capital expenditures	$	190	$	—	$	3	$	1	$	23	$	—	$	217

The following table summarizes balance sheet information by segment:


	As of March 31, 2026
(In millions)	Texas		East		West/Other		Vivint Smart Home		Corporate		Eliminations		Total

Goodwill(a)	$	2,234	$	2,996	$	128	$	3,523	$	—	$	—	$	8,881
Total assets	15,392		24,557		2,870		6,830		31,207		(40,803)		40,053
(a) The goodwill associated with the acquisition of the LSP Portfolio has been preliminarily allocated to the Texas and East segments as of March 31, 2026

	As of December 31, 2025
(In millions)	Texas		East		West/Other		Vivint Smart Home		Corporate		Eliminations		Total

Goodwill	$	643	$	721	$	130	$	3,523	$	—	$	—	$	5,017
Total assets	9,286		9,731		2,724		6,752		20,951		(20,304)		29,140

Note 12 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:


	Three months ended March 31,
(In millions, except rates)	2026			2025
Income before income taxes	$	83		$	985
Income tax (benefit)/expense	(42)			235

Effective income tax rate	(50.6)		%	23.9		%

For the three months ended March 31, 2026, the effective tax rate was lower than the statutory rate of 21%, primarily due to favorable permanent differences related to stock-based compensation and the remeasurement of state net operating losses as a result of the acquisition of the LSP Portfolio. For the three months ended March 31, 2025, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense.

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 applicable to NRG beginning in 2025. The impact of the OBBB on the Company’s condensed consolidated financial statements has been reflected in its first quarter current and deferred taxes, however, there is no material impact to the income tax (benefit)/expense for the three months ended March 31, 2026.

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 months ended March 31, 2026 and 2025.

Uncertain Tax Benefits

As of March 31, 2026, 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 three months ended March 31, 2026, NRG accrued $1 million of interest relating to the uncertain tax benefits. As of March 31, 2026, NRG had cumulative interest and penalties related to these uncertain tax benefits of $6 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 2022. 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 March 31,
(In millions)	2026		2025
Revenues from Related Parties Included in Revenue
Gladstone	$	1	$	1

Ivanpah(a)	21		12
Midway-Sunset	1		1


Total	$	23	$	14

(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 March 31, 2026, counterparties’ net exposure to NRG of approximately $203 million on out-of-the-money hedges was secured by the first lien structure.

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 has not yet been scheduled. This matter was known and accrued for at the time of the XOOM acquisition.

Telephone Consumer Protection Act (“TCPA”) Case

Matthew Dickson v. Direct Energy (N.D. Ohio Jan. 2018) — The Company is currently defending a putative class action involving 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 Company denies the allegations asserted by plaintiffs and intends to vigorously defend this matter. This matter was known and accrued for at the time of the Direct Energy acquisition. This 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. On December 16, 2025, the Court granted summary judgment in favor of Direct Energy. The Court subsequently entered default judgments against the remaining two defendants. Dickson timely filed their appeal.

Winter Storm Uri Lawsuits

The Company has been named in certain property damage and wrongful death claims that have been filed in connection with Winter Storm Uri in its capacity as a generator and a retail electric provider. 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 to the Texas Supreme Court. On March 27, 2026, the Texas Supreme Court denied review of the plaintiffs’ appeal. NRG awaits the trial court’s application of the dismissal across all of the cases filed against the generators. The Company will continue 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 proceeding noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect NRG’s consolidated financial position, results of operations, or cash flows.

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. 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. NRG responded to the notices in February 2024 and on September 23, 2025, the NYSPSC issued a follow-up order further alleging separately that the NRG retail supplier responsible for selling natural gas to commercial and industrial customers had been improperly serving residential customers. On April 16, 2026, the NYSPSC approved a settlement agreement which resolved all outstanding claims and permitted NRG to maintain its eligibility to serve customers. The agreement requires NRG to: (i) establish a $50 million fund for distribution to certain legacy customers; (ii) offer those same customers a one-time opportunity to enroll on a special discounted 12-month rate; and (iii) distribute approximately $920 thousand to certain low-income customers. This matter was accrued for as of March 31, 2026.

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. Future laws may 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 that indicate that the current administration intends to relax or rescind some previously promulgated regulations. The EPA has proposed several and finalized some rules that relax and/or rescind regulations previously promulgated. 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 U.S. Court of Appeals for the D.C. Circuit (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 would 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. In February 2025, the court granted a motion the DOJ filed asking the court to hold proceedings in abeyance while the EPA evaluates the rule. 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. The Company believes that the EPA may amend such regulations this year.

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 (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 March 13, 2026, the Fifth Circuit issued a revised opinion vacating and remanding the EPA’s disapproval of Texas’s interstate transport plan. 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. On January 30, 2026, the EPA proposed a Phase 1 reconsideration rule covering Alabama, Arizona, Iowa, Kansas, Kentucky, Minnesota, Mississippi, Nevada, New Mexico and Tennessee. The EPA intends to address additional states in a separate action. 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 — 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. The Company does not expect this proposal to be finalized during the current U.S. presidential administration. On December 5, 2025, the EPA approved Texas’s plans to address the Regional Haze rule.

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. On February 24, 2026, the EPA promulgated a final rule repealing the majority of the 2024 rule amending the MATS rule.

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 U.S. Court of Appeals for the Eighth Circuit. 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 December 31, 2025, the EPA promulgated a rule that extends several deadlines and provides greater flexibility regarding decisions to invest in more stringent controls.

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. On February 10, 2026, the EPA promulgated a rule extending certain deadlines in the 2024 rule. On April 13, 2026, the EPA proposed further amendments to the CCR that if finalized would provide industry greater compliance flexibility. 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 months ended March 31, 2026 and 2025. Also refer to NRG’s 2025 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, provides electricity, natural gas, and smart-home technology solutions to approximately 8 million residential customers (comprised of 6 million retail energy and 2 million smart home), in addition to large commercial and industrial, data center and wholesale customers. Across North America, NRG is redefining customer’s experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of March 31, 2026, the Company’s core power and natural gas business consists of approximately 25 GW of competitive power generation, including approximately 13 GW from the LSP portfolio, and a natural gas portfolio that serves approximately 1,900 MMDth annually.

Strategy

NRG’s strategy is to maximize shareholder value by delivering integrated energy and smart home solutions, supported by an owned generation fleet and a diversified supply strategy. The Company generates power and sells electricity and natural gas to residential, commercial, industrial, and wholesale customers in the markets it serves. The Company also provides smart home security and automation services that deepen customer relationships and support long-term engagement. NRG operates a customer-first platform that promotes reliability and affordability amid rapid transformation in the energy sector. The Company is advancing opportunities to meet growing demand, including from data centers, other large load customers, and electrification. This includes (i) demand response and virtual power plants (“VPP”), which help manage costs and improve affordability for customers, (ii) completing the Texas Development Projects, (iii) long-term, contract-backed generation and related infrastructure, supported by strategic partnerships with equipment manufacturers and engineering, procurement, and construction companies, and (iv) increasing capacity at existing facilities. The Company’s differentiated model is built to meet North America’s evolving needs while delivering affordable, reliable solutions for customers and long-term growth for shareholders. This strategy is intended to generate recurring cash flow, strengthen earnings and cost competitiveness, and reduce risk and volatility.

To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of 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, value-additive features, premium service, integrated platforms, sustainability, loyalty/affinity programs, and affordability; (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, including expanding its operational capacity to meet growing retail power supply needs; and (v) engaging in disciplined and transparent capital allocation.

In the first quarter of 2026, the operations acquired from LS Power were integrated into the Company’s existing segment structure, enhancing scale and portfolio optimization across the platform. In Texas, the Company’s generation portfolio is fully integrated with its retail load and in early 2026, the Company adopted an integrated strategy in the East, expanding this model across a broader geographic footprint. The integrated model strategically aligns generation and retail, enabling the Company to supply a portion of its retail customers with electricity from Company-owned assets, thereby reducing reliance to procure electricity from other institutions and intermediaries and supporting more stable earnings and cash flows, lower transaction costs, and reduced credit exposure. The integrated model also results in a reduction in actual and contingent collateral requirements, improving capital efficiency and further limiting transactions with third parties.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2025 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 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 (“SB”) 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, 2026. 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 SB 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 Court of Appeals for the Fourth Circuit and oral argument occurred on October 24, 2025. The appeal is pending.

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

PUCT’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 indefinitely. The Texas Legislature also directed the PUCT to implement 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. In November 2025, ERCOT published an updated design proposal for DRRS that includes the ability for the PUCT to configure it to support resource adequacy through stronger financial incentives for dispatchable thermal generation. The PUCT will evaluate the final design of DRRS as part of the review of the reliability standard in 2026. The PUCT adopted a final rule to implement the firming requirement in December 2025, which requires new generation resources with signed interconnection agreements on or after January 1, 2027, to acquire additional capacity to meet a minimum requirement during low reserve hours on the ERCOT system.

Texas Energy Fund — Through SB 2627, the Texas Legislature created the TEF, to provide grants and low-interest loans (3%) to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT. 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. The

89th Texas Legislature passed SB 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.

NRG, through its subsidiaries, filed and received approval from the PUCT for loan proceeds for three separate projects, totaling more than 1,500 MWs of capacity. Specifically, on July 31, 2025, the Company entered into a $216 million loan agreement with the PUCT under the TEF to support the development of T.H. Wharton, a 415 MW facility. On December 12, 2025, the PUCT approved the notice of eligibility for the completion bonus grant for T.H. Wharton. On September 26, 2025, the Company entered into a $562 million loan agreement with the PUCT under the TEF to support the development of Cedar Bayou 5, a 689 MW facility. Lastly, on November 20, 2025, the Company entered into a $370 million loan agreement with the PUCT under the TEF to support the development of Greens Bayou 6, a 443 MW facility. All three projects are currently under construction. Commercial operations at T.H. Wharton is expected by the end of May 2026.

Senate Bill 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 improves load forecasting accuracy 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. The PUCT rulemaking process for these components of SB 6 is in progress. On March 27, 2026, the PUCT published its proposed rule relating to large load interconnection standards, which establishes the standards and criteria to interconnect a large load customer to the ERCOT system, as well as the financial security large load customers would need to provide. A final rule is anticipated in the third quarter of 2026. ERCOT is also developing revisions to the interconnection study process to more efficiently review large load interconnection requests.

PJM

Revisions to PJM Locational Deliverability Area (“LDA”) Reliability Requirement — PJM delayed publication of the Base Residual Auction (“BRA”) results for the 2024/2025 delivery year and filed at FERC to revise the definition of the LDA Reliability Requirement in the Tariff to allow PJM to exclude certain resources from the calculation of the LDA Reliability Requirement, which FERC accepted on February 21, 2023. Multiple parties, including NRG, filed for rehearing and subsequently appealed to the Court of Appeals for the Third Circuit. On March 12, 2024, the court vacated the portion of the FERC orders permitting application of the revised LDA Reliability Requirement to the 2024/2025 BRA. Following additional proceedings, FERC directed PJM to recalculate the BRA results using the original LDA Reliability Requirements and to rerun the Third Incremental Auction, and PJM published revised results on May 8, 2024, and May 23, 2024, respectively. On July 9, 2024, FERC denied a related complaint filed on April 22, 2024 (the “April 2024 Complaint”) which was appealed to the Court of Appeals for the D.C. Circuit on November 5, 2024. On January 13, 2026, the Court of Appeals for the D.C. Circuit issued a decision vacating FERC’s order denying the April 2024 Complaint and remanding the case to FERC for a ruling on the substance of the complaint. The remanded complaint is pending at FERC.

PJM Base Residual Auction Revisions and Delay — In November 2024, at PJM’s request, FERC approved delays to future BRAs. The 2028/2029 BRA is scheduled to occur in May 2026 and is the last delayed auction affected.

PJM’s Reforms to Large Load Additions — On September 15, 2025, PJM began a formal stakeholder process called the Critical Issue Fast Path (“CIFP”) to address needed reforms to accommodate large load additions. On January 16, 2026, the National Energy Dominance Council within the White House released a Statement of Principles, signed by all 13 governors in the PJM region, urging PJM to address revenue certainty for new generation through an auction process for new capacity, allocate the costs of these new resources to data centers, improve load forecasting, and accelerate ongoing generation interconnection studies. Also on January 16, 2026, the PJM Board issued a decisional letter on the CIFP process. The Board letter directed PJM staff to implement changes to load forecasting, implement a bring your own new generation program and associated expedited interconnection track, initiate immediately a Reliability Backstop Auction to obtain commitments of additional generation for a longer term, and undertake a holistic review of the PJM markets to analyze how they can evolve to provide appropriate incentives for investment and performance. On February 27, 2026, PJM made two filings at FERC. In its first filing, PJM proposed an expedited interconnection track for up to ten qualified large load projects. This filing is pending at FERC. In its second filing, PJM proposed an extension of the price cap and price floor for all capacity auctions through the 2028/2029 and 2029/2030 delivery years. On April 28, 2026, FERC approved PJM’s second filing to extend the price cap and price floor.

On April 10, 2026, PJM published a Reliability Backstop Procurement proposal in response to the January 16, 2026 Board directive. PJM proposes a one-time, transitional procurement of capacity in two-stages. An initial process for facilitating bilateral contracts between large loads and eligible supply, beginning in September 2026 and ending in March 2027, followed by a central procurement process to commence in March 2027. PJM expects to file at FERC to implement these changes in June 2026, following an abbreviated stakeholder process. The implementation of these market changes could have material impacts on the PJM market.

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 Court of Appeals for the Fourth Circuit of FERC’s denial on its request for rehearing. On August 22, 2025, NRG filed a motion to transfer venue. On November 12, 2025, the motion to transfer venue was granted and the appeal was transferred to the Court of Appeals for the D.C. Circuit. The appeal is pending.

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. Future laws may 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 that indicate that the current administration intends to relax or rescind some previously promulgated regulations. The EPA has proposed several and finalized some rules that relax and/or rescind regulations previously promulgated. 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 2025 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 but in November 2025, the EPA asked the DC Circuit to vacate the March 2024 rule. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent requirements 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.

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 would 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. In February 2025, the court granted a motion the DOJ filed asking the court to hold proceedings in abeyance while the EPA evaluates the rule. 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 just specific portions. On February 18, 2026, the EPA rescinded the 2009 GHG Endangerment Finding related to motor vehicle emissions. Although this rescission does not directly alter the GHG regulations related to power plants, the Company believes that the EPA may amend such regulations this year.

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 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 March 13, 2026, the Fifth Circuit issued a revised opinion vacating and remanding the EPA’s disapproval of Texas’s interstate transport plan. 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. On January 30, 2026, the EPA proposed a Phase 1 reconsideration rule covering Alabama, Arizona, Iowa, Kansas, Kentucky, Minnesota, Mississippi, Nevada, New Mexico and Tennessee. The EPA intends to address additional states in a separate action. The Company cannot predict the outcome of the legal challenges to the various state disapprovals and the final rule promulgated on June 5, 2023.

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. On February 24, 2026, the EPA promulgated a final rule repealing the majority of the 2024 rule amending the MATS 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.

31, 2025, the EPA promulgated a rule that extends several deadlines and provides greater flexibility regarding decisions to invest in more stringent controls.

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. On February 10, 2026, the EPA promulgated a rule extending certain deadlines in the 2024 rule. On April 13, 2026, the EPA proposed further amendments to the CCR that if finalized would provide industry greater compliance flexibility. The rule has been challenged in the D.C. Circuit and the outcome of the legal challenges is uncertain.

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.

Virginia Rejoining the Regional Greenhouse Gas Initiative (“RGGI”) — On February 20, 2026, Virginia enacted legislation to rejoin the RGGI. Virginia is working on promulgating the implementing regulations and is seeking to require compliance beginning on July 1, 2026.

Significant Events

The following significant events have occurred during 2026 as further described within this Management’s Discussion and Analysis and the condensed consolidated financial statements:

Acquisition of LSP Portfolio

On January 30, 2026, NRG completed the acquisition of the LSP Portfolio from LS Power. The acquisition doubles NRG’s generation capacity with the addition of 18 natural gas-fired and dual fuel facilities totaling approximately 13 GW. In addition, NRG acquired CPower, a leading demand response platform, which operates in all the country’s deregulated energy markets and has more than 2,000 commercial and industrial customers. The consideration consisted of 24.25 million shares of NRG common stock and $6.4 billion in cash, plus preliminary working capital and certain other adjustments of $483 million. The Company funded the cash consideration using a portion of the net proceeds of $4.4 billion from the 5.750% 2034 Senior Notes, the 2036 Senior Notes, Senior Secured First Lien Notes, due 2030 and the Senior Secured First Lien Notes, due 2035 and proceeds of $2.5 billion from the Company’s Revolving Credit Facility. For further discussion, see Note 4, Acquisitions.

Capital Allocation

During the three months ended March 31, 2026, the Company completed $481 million of share repurchases at an average price of $161.16 per share. Through April 30, 2026, an additional $338 million of share repurchases were executed at an average price of $156.52 per share. See Note 9, Changes in Capital Structure for additional discussion.

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

Term Loan B Incurrence

On April 28, 2026, the Company and APX Group LLC, as borrowers, and certain of the Company’s subsidiaries, as guarantors, entered into the Sixteenth Amendment to the Credit Agreement. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Issuance of Unsecured Notes and Secured Notes

On April 28, 2026, the Company issued $2.1 billion in aggregate principal amount of 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 loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.

On April 28, 2026, the Company also issued $500 million aggregate principal amount of the New 2031 Notes. The New 2031 Notes are senior secured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Bilateral Letter of Credit Facilities

Lightning Tender Offer and Redemption

On April 14, 2026, Lightning commenced the Tender Offer. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Further, pursuant to the terms of the Lightning Indenture, on April 28, 2026, Lightning issued the Redemption to redeem the remaining $5 million aggregate principal amount of the Lightning 2032 Notes at a redemption price of 101.375% (plus accrued and unpaid interest to, but excluding, the redemption date). For further discussion, see Note 7, Long-term Debt and Finance Leases.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2025 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:

Geopolitical Developments — The ongoing geopolitical conflicts, including hostilities with Iran and conflicts in the Middle East, have contributed to elevated and volatile oil prices and could, over time, put upward pressure on U.S. natural gas. Prolonged market volatility could result in increased collateral requirements and heighten counterparty credit exposure under NRG’s hedging arrangements.

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 March 31,
(In millions)	2026		2025		Change
Revenue
Retail revenue	$	9,500	$	8,216	$	1,284
Energy revenue(a)	475		245		230
Capacity revenue(a)	239		47		192
Mark-to-market for economic hedging activities	(42)		(15)		(27)
Contract amortization	6		(5)		11
Other revenues(a)(b)	78		97		(19)
Total revenue	10,256		8,585		1,671
Operating Costs and Expenses
Cost of fuel	444		334		(110)
Purchased energy and other cost of sales(c)	7,697		6,182		(1,515)

Mark-to-market for economic hedging activities	163		(346)		(509)
Contract and emissions credit amortization(c)	17		25		8
Operations and maintenance	433		288		(145)
Other cost of operations	104		78		(26)
Cost of operations (excluding depreciation and amortization shown below)	8,858		6,561		(2,297)
Depreciation and amortization	432		326		(106)

Selling, general and administrative costs (excluding amortization of customer acquisition costs of $87 and $65, respectively, which are included in depreciation and amortization shown separately above)	593		549		(44)

Acquisition-related transaction and integration costs	45		8		(37)
Total operating costs and expenses	9,928		7,444		(2,484)

Loss on sale of assets	—		(7)		7
Operating Income	328		1,134		(806)
Other Income/(Expense)


Other income, net	40		14		26

Interest expense	(285)		(163)		(122)
Total other expense	(245)		(149)		(96)
Income Before Income Taxes	83		985		(902)
Income tax (benefit)/expense	(42)		235		277




Net Income	$	125	$	750	$	(625)

(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 March 31, 2026 and 2025

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended March 31, 2026 and 2025:


	Average on Peak Power Price ($/MWh)
	Three months ended March 31,
Region	2026		2025		Change %
Texas
ERCOT - Houston(a)	$	29.03	$	33.26	(13)	%
ERCOT - North(a)	27.46		35.38		(22)	%

East
NY J/NYC(b)	$	134.66	$	110.45	22	%
NEPOOL(b)	122.69		108.83		13	%
COMED (PJM)(b)	59.83		42.21		42	%
PJM - West Hub(b)	103.38		60.16		72	%
PJM - APS(b)	102.74		57.52		79	%
PJM - DOMINION(b)	110.81		64.33		72	%

West
MISO - Louisiana Hub(b)	$	50.32	$	47.14	7	%
CAISO - SP15(b)	22.05		26.46		(17)	%

(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 March 31, 2026 and 2025:


	Three months ended March 31,
	2026		2025		Change %
($/MMBtu)	$	5.04	$	3.65	38	%

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 March 31, 2026 and 2025:


	Three months ended March 31, 2026
($ In millions)	Texas(a)		East(a)		West/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	2,335	$	5,737	$	862	$	578	$	(12)	$	9,500
Energy revenue	8		467		—		—		—		475
Capacity revenue	—		239		—		—		—		239
Mark-to-market for economic hedging activities	—		(44)		—		—		2		(42)
Contract amortization	—		6		—		—		—		6
Other revenue(b)	50		27		2		—		(1)		78
Total revenue	2,393		6,432		864		578		(11)		10,256
Cost of fuel	(214)		(229)		(1)		—		—		(444)
Purchased energy and other cost of sales(c)(d)(e)	(1,494)		(5,442)		(710)		(52)		1		(7,697)
Mark-to-market for economic hedging activities	(51)		(56)		(54)		—		(2)		(163)
Contract and emissions credit amortization	(2)		(14)		(1)		—		—		(17)
Depreciation and amortization	(108)		(102)		(8)		(200)		(14)		(432)
Gross margin	$	524	$	589	$	90	$	326	$	(26)	$	1,503
Less: Mark-to-market for economic hedging activities, net	(51)		(100)		(54)		—		—		(205)
Less: Contract and emissions credit amortization, net	(2)		(8)		(1)		—		—		(11)
Less: Depreciation and amortization	(108)		(102)		(8)		(200)		(14)		(432)
Economic gross margin	$	685	$	799	$	153	$	526	$	(12)	$	2,151
(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026
(b) Includes trading gains and losses and ancillary revenues
(c) Includes capacity and emissions credits
(d) Includes $778 million, $58 million and $273 million of TDSP expense in Texas, East and West/Other, respectively
(e) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	7,383		4,125		720		—		—		12,228
Business electricity sales volume (GWh)	8,864		10,993		3,131		—		—		22,988
Home natural gas sales volume (MDth)	—		22,385		32,485		—		—		54,870
Business natural gas sales volume (MDth)	—		533,485		58,296		—		—		591,781
Average retail Home customer count (in thousands)(a)	2,850		2,133		647		—		—		5,630
Ending retail Home customer count (in thousands)(a)	2,831		2,171		645		—		—		5,647
Average Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,408		—		2,408
Ending Vivint Smart Home customer count (in thousands) (b)(c)	—		—		—		2,427		—		2,427
Power generation
GWh sold(d)	5,437		4,431		1		—		—		9,869
GWh generated
Coal	3,839		728		—		—		—		4,567
Gas	1,598		3,225		—		—		—		4,823


Oil	—		18		—		—		—		18
Renewables	—		—		1		—		—		1
Total	5,437		3,971		1		—		—		9,409
(a) Home customer count includes recurring residential customers and community choice
(b) Vivint Smart Home includes customers that also purchase other NRG products such as electricity
(c) Vivint Smart Home includes 62 thousand Home Protection (non-Vivint) customers
(d) Includes GWh sold from owned and tolled generation, excludes equity investments. Cottonwood lease ended in May 2025


	Three months ended March 31, 2025
($ In millions)	Texas		East		West/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	2,387	$	4,350	$	972	$	511	$	(4)	$	8,216
Energy revenue	7		158		81		—		(1)		245
Capacity revenue	—		40		8		—		(1)		47
Mark-to-market for economic hedging activities	—		(19)		2		—		2		(15)
Contract amortization	—		(5)		—		—		—		(5)
Other revenue(a)	41		53		7		—		(4)		97
Total revenue	2,435		4,577		1,070		511		(8)		8,585
Cost of fuel	(177)		(108)		(49)		—		—		(334)
Purchased energy and other cost of sales(b)(c)(d)	(1,521)		(3,752)		(876)		(36)		3		(6,182)
Mark-to-market for economic hedging activities	38		308		2		—		(2)		346
Contract and emissions credit amortization	(1)		(24)		—		—		—		(25)
Depreciation and amortization	(83)		(37)		(9)		$	(186)	(11)		(326)
Gross margin	$	691	$	964	$	138	$	289	$	(18)	$	2,064
Less: Mark-to-market for economic hedging activities, net	38		289		4		—		—		331
Less: Contract and emissions credit amortization, net	(1)		(29)		—		—		—		(30)
Less: Depreciation and amortization	(83)		(37)		(9)		(186)		(11)		(326)
Economic gross margin	$	737	$	741	$	143	$	475	$	(7)	$	2,089
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $800 million, $64 million and $423 million of TDSP expense in Texas, East, and West/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	8,465		4,157		681		—		—		13,303
Business electricity sales volume (GWh)	8,928		11,095		2,914		—		—		22,937
Home natural gas sales volume (MDth)	—		26,640		35,104		—		—		61,744
Business natural gas sales volume (MDth)	—		500,579		54,070		—		—		554,649
Average retail Home customer count (in thousands)(a)	2,911		2,203		649		—		—		5,763
Ending retail Home customer count (in thousands)(a)	2,955		2,219		651		—		—		5,825
Average Vivint Smart Home customer count (in thousands)(b)	—		—		—		2,230		—		2,230
Ending Vivint Smart Home customer count (in thousands)(b)(c)	—		—		—		2,241		—		2,241
Power generation
GWh sold(d)	5,641		1,923		1,544		—		—		9,108
GWh generated
Coal	4,810		1,209		—		—		—		6,019
Gas	831		1		1,543		—		—		2,375

Oil	—		3		—		—		—		3
Renewables	—		—		1		—		—		1
Total	5,641		1,213		1,544		—		—		8,398
(a) Home customer count includes recurring residential customers and community choice
(b) Vivint Smart Home includes customers that also purchase other NRG products such as electricity
(c) Vivint Smart Home includes 72 thousand Home Protection (non-Vivint) customers
(d) Includes GWh sold from owned, tolled and leased generation, excludes equity investments

The following table represents the weather metrics for the three months ended March 31, 2026 and 2025:


	Three months ended March 31,
Weather Metrics	Texas	East(b)	West/Other(c)
2026
CDDs(a)	228	23	118
HDDs(a)	710	2,779	825
2025
CDDs	152	17	65
HDDs	1,014	2,757	1,181
10-year average
CDDs	128	23	57
HDDs	912	2,614	1,095

(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 East weather metrics are comprised of the average of the CDD and HDD regional results for the Northeast and East - Midwest regions

(c) The West/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 decreased $561 million and economic gross margin increased $62 million during the three months ended March 31, 2026, compared to the same period in 2025.

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

Texas


	(In millions)
Higher gross margin due to the net effect of: •an increase in net revenue rates of $86 million, primarily driven by changes in customer term, product and mix •a 12%, or $76 million increase in cost to serve the retail load, driven by higher realized power prices associated with the Company’s diversified supply strategy, including the assets acquired from the LSP Portfolio	$	10
Lower gross margin due to a decrease in load of 0.7 TWhs, or $32 million, attributed to weather, as well as a decrease in load of 0.4 TWhs, or $27 million, driven by changes in customer mix and attrition	(59)

Other	(3)
Decrease in economic gross margin	$	(52)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(89)
Increase in contract and emissions credit amortization	(1)
Increase in depreciation and amortization	(25)
Decrease in gross margin	$	(167)

East


	(In millions)
Lower electric gross margin due to the net effect of: •a 31%, or $374 million increase in cost to serve the retail load, driven by higher realized power prices associated with the Company’s diversified supply strategy, including the assets acquired from the LSP Portfolio •an increase in net revenue rates of $262 million, primarily driven by changes in customer term, product and mix	$	(112)
Higher electric gross margin primarily due to changes in customer mix and attrition, as well as an increase in load attributed to weather	12
Lower natural gas gross margin due to higher supply costs of $1,021 million including the impact of transportation and storage contract optimization, partially offset by higher net revenue rates of $1,005 million, from changes in customer term, product, and mix	(16)
Higher natural gas gross margin from an increase in load due to a change in customer mix	11
Higher gross margin due to an increase in capacity from the acquisition of the LSP Portfolio and Midwest Generation	150
Higher gross margin due to an increase in demand response activities, including the acquisition of CPower and higher PJM auction prices in 2026	26
Lower gross margin due to the deactivation of Indian River Unit 4 in February 2025	(9)

Other	(4)
Increase in economic gross margin	$	58
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(389)
Decrease in contract amortization	21
Increase in depreciation and amortization	(65)
Decrease in gross margin	$	(375)

West/Other


	(In millions)
Higher electric gross margin due to lower supply costs of $23 million and customer mix of $4 million, partially offset by lower net revenue rates of $6 million	$	21
Lower natural gas gross margin due to higher supply costs of $29 million, partially offset by higher net revenue rates of $25 million and higher customer mix of $1 million	(3)





Other	(8)
Increase in economic gross margin	$	10
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(58)
Increase in contract amortization	(1)
Decrease in depreciation and amortization	1
Decrease in gross margin	$	(48)

Vivint Smart Home


	(In millions)
Higher gross margin primarily driven by growth in customers of $31 million and higher monthly revenue of $3 million	$	34

Higher gross margin in home protection due to increased sales volume	16

Other	1
Increase in economic gross margin	$	51


Increase in depreciation and amortization	(14)
Increase in gross margin	$	37

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 $536 million during the three months ended March 31, 2026, compared to the same period in 2025.

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


	Three months ended March 31, 2026
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	—	$	(28)	$	—	$	1	$	(27)
Reversal of acquired gain positions related to economic hedges	—		(9)		—		—		(9)
Net unrealized losses on open positions related to economic hedges	—		(7)		—		1		(6)
Total mark-to-market losses in revenue	$	—	$	(44)	$	—	$	2	$	(42)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)	$	(43)	$	(51)	$	88	$	(1)	$	(7)
Reversal of acquired (gain)/loss positions related to economic hedges	(1)		20		—		—		19
Net unrealized losses on open positions related to economic hedges	(7)		(25)		(142)		(1)		(175)
Total mark-to-market losses in operating costs and expenses	$	(51)	$	(56)	$	(54)	$	(2)	$	(163)

(a)Includes $(51) 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


	Three months ended March 31, 2025
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	—	$	(1)	$	(3)	$	—	$	(4)

Net unrealized (losses)/gains on open positions related to economic hedges	—		(18)		5		2		(11)
Total mark-to-market (losses)/gains in revenue	$	—	$	(19)	$	2	$	2	$	(15)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)	$	(145)	$	(123)	$	54	$	—	$	(214)
Reversal of acquired loss/(gain) positions related to economic hedges	3		(7)		—		—		(4)
Net unrealized gains/(losses) on open positions related to economic hedges	180		438		(52)		(2)		564
Total mark-to-market gains/(losses) in operating costs and expenses	$	38	$	308	$	2	$	(2)	$	346

(a)Includes $(83) 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

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 March 31, 2026, the $42 million loss in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $163 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 natural gas prices and CAISO and Alberta power prices.

For the three months ended March 31, 2025, the $15 million loss in revenues from economic hedge positions was driven primarily by a decrease in the value of East open positions as a result of increases in Northeast power prices. The $346 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions in Texas and East as a result of increases in natural gas prices and ERCOT and Northeast power prices, partially offset by 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 March 31, 2026 and 2025. The realized and unrealized financial and physical trading results are included in revenue. The Company’s trading activities are subject to limits based on the Company’s Risk Management Policy.


	Three months ended March 31,
(In millions)	2026		2025
Trading gains/(losses)
Realized	$	2	$	4
Unrealized	(7)		(4)
Total trading losses	$	(5)	$	—

Operations and Maintenance Expense

Operations and maintenance expense is comprised of the following:


(In millions)	Texas(a)		East(a)		West/Other		Vivint Smart Home		Corporate/Eliminations		Total

Three months ended March 31, 2026	$	222	$	127	$	13	$	71	$	—	$	433
Three months ended March 31, 2025	94		101		32		62		(1)		288

(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026

Operations and maintenance expense increased by $145 million for the three months ended March 31, 2026, compared to the same period in 2025, due to the following:


	(In millions)
Increase primarily due to the acquisition of the LSP Portfolio in January 2026	$	59

Decrease driven by the expiration of the Cottonwood facility lease in May 2025	(19)
Increase due to the final property insurance claim for the extended outage at W.A. Parish received in 2025	100


Increase driven by higher retail operations costs	12
Increase driven by higher Vivint Smart Home operations costs to support customer growth	7
Decrease due to timing of planned major maintenance expenditures at Powerton	(11)
Other	(3)
Increase in operations and maintenance expense	$	145

Other Cost of Operations

Other cost of operations is comprised of the following:


(In millions)	Texas(a)		East(a)		West/Other		Vivint Smart Home		Total

Three months ended March 31, 2026	$	54	$	48	$	1	$	1	$	104
Three months ended March 31, 2025	55		19		3		1		78

(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026

Other cost of operations for the three months ended March 31, 2026 increased by $26 million, when compared to the same period in 2025, due to the following:


	(In millions)
Increase due to the acquisition of the LSP Portfolio in January 2026	$	7

Increase primarily due to changes in prior year ARO cost estimates at Midwest Generation	16
Other	3
Increase in other cost of operations	$	26

Depreciation and Amortization

Depreciation and amortization are comprised of the following:


(In millions)	Texas(a)		East(a)		West/Other		Vivint Smart Home		Corporate		Total
Three months ended March 31, 2026	$	108	$	102	$	8	$	200	$	14	$	432
Three months ended March 31, 2025	83		37		9		186		11		326

(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026

Depreciation and amortization increased by $106 million for the three months ended March 31, 2026, compared to the same period in 2025, due to the following:


	(In millions)
Increase due to the acquisition of the LSP Portfolio in January 2026	$	79
Increase in amortization of capitalized contract costs primarily in the Vivint Smart Home segment	47
Decrease in amortization driven by the expected roll off of the acquired Vivint Smart Home intangibles	(25)

Other	5
Increase in depreciation and amortization	$	106

Selling, General and Administrative Costs

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


(In millions)	Texas(a)		East(a)		West/Other		Vivint Smart Home		Corporate/Elimination		Total
Three months ended March 31, 2026	$	219	$	176	$	29	$	176	$	(7)	$	593
Three months ended March 31, 2025	205		143		32		163		6		549

(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026

Selling, general and administrative costs increased by $44 million for the three months ended March 31, 2026, compared to the same period in 2025, due to the following:


	(In millions)
Increase due to the acquisition of the LSP Portfolio in January 2026	$	5
Increase in personnel costs	25
Increase in broker fee and commissions expenses	14

Increase in marketing and media expenses	11

Decrease in reserves for legal matters	(17)
Other	6
Increase in selling, general and administrative costs	$	44

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $45 million and $8 million for the three months ended March 31, 2026 and 2025, respectively, include:


	Three months ended March 31,
(In millions)	2026		2025
LSP Portfolio acquisition costs	$	38	$	—
LSP Portfolio integration costs	4		—
Other integration costs, primarily related to Vivint Smart Home	3		8



Acquisition-related transaction and integration costs	$	45	$	8

Other Income, net

Other income, net increased by $26 million for the three months ended March 31, 2026, compared to the same period in 2025, primarily driven by higher interest income.

Interest Expense

Interest expense increased by $122 million for the three months ended March 31, 2026, compared to the same period in 2025, primarily due to the LSP acquisition including the impact related to the issuance of unsecured notes, secured notes, and borrowings on the Revolving Credit Facility used to fund the cash portion of the consideration, as well as the acquired Lightning debt. For further discussion, see Note 4, Acquisitions

Income Tax (Benefit)/Expense

For the three months ended March 31, 2026, income tax benefit of $42 million was recorded on pre-tax income of $83 million. For the same period in 2025, an income tax expense of $235 million was recorded on pre-tax income of $985 million. The effective tax rates were (50.6)% and 23.9% for the three months ended March 31, 2026 and 2025, respectively.

For the three months ended March 31, 2026 the effective tax rate was lower than the statutory rate of 21%, primarily due to favorable permanent differences related to stock-based compensation and the remeasurement of state net operating losses as a result of the acquisition of the LSP portfolio. For the same period in 2025, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense.

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2026 and December 31, 2025, NRG’s total liquidity, excluding funds deposited by counterparties, of approximately $3.3 billion and $9.6 billion, respectively, was comprised of the following:


(In millions)	March 31, 2026		December 31, 2025
Cash and cash equivalents	$	178	$	4,708
Restricted cash - operating	25		12
Restricted cash - reserves(a)	32		18
Total	235		4,738
Total availability under Revolving Credit Facility and collective collateral facilities(b)	3,015		4,890
Total liquidity, excluding funds deposited by counterparties	$	3,250	$	9,628

(a) Includes reserves primarily for capital expenditures

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $9.3 billion and $7.7 billion as of March 31, 2026 and December 31, 2025, respectively

For the three months ended March 31, 2026, total liquidity, excluding funds deposited by counterparties, was approximately $3.3 billion, which is $6.4 billion lower than December 31, 2025, primarily driven by the use of cash and borrowings under the Revolving Credit Facility to fund the acquisition of LSP Portfolio. Changes in cash and cash equivalent balances are further discussed under the heading Cash Flow Discussion. Cash and cash equivalents at March 31, 2026 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, tax-exempt bonds, and TEF loans. The Company also issues letters of credit through bilateral letter of credit facilities and the pre-capitalized trust securities facility. As part of the acquisition of the LSP Portfolio on January 30, 2026, NRG acquired existing debt, which includes the Lightning Senior Secured Notes, Lightning Term Loan, and Lightning Revolving 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.

Acquisition of LSP Portfolio

On January 30, 2026, NRG completed the acquisition of the LSP Portfolio from LS Power. The consideration consisted of 24.25 million shares of NRG common stock and $6.4 billion in cash, plus preliminary working capital and certain other adjustments of $483 million. The Company funded the cash consideration using a portion of the net proceeds from the 5.750% 2034 Senior Notes, the 2036 Senior Notes, Senior Secured First Lien Notes, due 2030 and the Senior Secured First Lien Notes, due 2035 of $4.4 billion and proceeds of $2.5 billion from the Company’s Revolving Credit Facility. For further discussion, see Note 4, Acquisitions.

Term Loan B Incurrence

Issuance of Unsecured Notes and Secured Notes

Bilateral Letter of Credit Facilities

Revolving Credit Facility

As of March 31, 2026, $3.0 billion of borrowings were outstanding. As of April 30, 2026, $1.5 billion of borrowings were outstanding.

Receivables Facility

As of March 31, 2026, $350 million of borrowings were outstanding. As of April 30, 2026, $200 million of borrowings were outstanding.

Lightning Notes

On the Acquisition Closing Date, Lightning remained the issuer of the Lightning Senior Secured Notes issued pursuant to the Lightning Indenture, by and among Lightning, Lightning’s subsidiaries that are guarantors from time to time party thereto, and the Lightning Notes Trustee. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Lightning Tender Offer and Redemption

On April 14, 2026, Lightning commenced the Tender Offer. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Lightning Credit Facility

On the Acquisition Closing Date, Lightning remained party to the Lightning Credit Agreement with Morgan Stanley Senior Funding, Inc. as administrative agent and collateral agent and various lenders and issuing banks from time to time party thereto. The Lightning Credit Agreement consists of the Lightning Term Loan and the Lightning Revolving Facility. As of March 31, 2026, there were no outstanding borrowings and there were $105 million in letters of credit issued under the Lightning Revolving Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Market Operations

The Company’s market operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (e.g., buying energy before receiving retail revenues); and (iv) initial collateral for large structured transactions. As of March 31, 2026, market operations had total cash collateral outstanding of $606 million and $3.0 billion outstanding in letters of credit to third parties primarily to support its market activities. As of March 31, 2026, total funds deposited by counterparties were $176 million in cash and $371 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.

As of March 31, 2026, counterparties’ net exposure to NRG of approximately $203 million on out-of-the-money hedges was secured by the first lien structure.

Capital Expenditures

The following table summarizes the Company’s capital expenditures for maintenance, environmental and investments and integration for the three months ended March 31, 2026, and the estimated forecast for the remainder of the year.


(In millions)	Maintenance		Environmental		Investments and Integration		Total
Texas	$	63	$	5	$	188	$	256
East	23		—		—		23
West/Other	1		—		2		3
Vivint Smart Home	2		—		—		2
Corporate	5		—		28		33
Total cash capital expenditures for the three months ended March 31, 2026	$	94	$	5	$	218	$	317
Integration operating expenses and cost to achieve	—		—		16		16
Investments	—		—		15		15
Total cash capital expenditures and investments for the three months ended March 31, 2026	$	94	$	5	$	249	$	348




Estimated cash capital expenditures and investments for the remainder of 2026	371		10		874		1,255
Estimated full year 2026 cash capital expenditures and investments	$	465	$	15	$	1,123	$	1,603

Investments and Integration for the three months ended March 31, 2026 include growth expenditures, integration, small book acquisitions and other investments.

Environmental Capital Expenditures Estimate

NRG estimates that environmental capital expenditures from 2026 through 2030 required to comply with environmental laws will be approximately $33 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 quarter ended March 31, 2026, the Company declared and paid a semi-annual 10.25% dividend of $51.25 per share on its outstanding Series A Preferred Stock, totaling $33 million.

Obligations under Certain Guarantees

NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the Company’s business activities. For further discussion, see Note 26, Guarantees, to the Company’s 2025 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 March 31, 2026. 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 2025 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 months ended March 31, 2026.

Cash Flow Discussion

The following table reflects the changes in cash flows for the three months ended March 31, 2026 and 2025, respectively:


	Three months ended March 31,
(In millions)	2026		2025		Change
Cash (used)/provided by operating activities	$	(169)	$	855	$	(1,024)
Cash used by investing activities	(7,072)		(134)		(6,938)
Cash provided/(used) by financing activities	2,652		(458)		3,110

Cash (used)/provided by operating activities

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


	(In millions)




Changes in cash collateral in support of risk management activities due to change in commodity prices	$	(765)
Decrease in operating income adjusted for derivatives and other non-cash items	(294)

Increase in working capital primarily due to timing of retail receipts partially offset by lower gas volumes in accounts payable	173
Decrease in working capital related to inventory primarily driven by increased coal volumes and increased cost of materials	(121)












Increase in other working capital	(17)
	$	(1,024)

Cash used by investing activities

Changes to cash used by investing activities were driven by:


	(In millions)




Increase in cash paid for acquisitions primarily due to the acquisition of the LSP Portfolio in January 2026	$	(6,735)
Increase in capital expenditures	(100)
Decrease due to proceeds from insurance recoveries for property, plant and equipment, net in 2025	(100)



Other	(3)
	$	(6,938)

Cash provided/(used) by financing activities

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


	(In millions)




Increase due to higher proceeds from credit facilities for the acquisition of the LSP Portfolio	$	3,325
Decrease primarily due to higher payments for share repurchase activities in 2026	(206)
Increase due to proceeds from TEF loans	57
Decrease due to higher deferred debt issuance costs	(39)
Increase in payments of dividends primarily due to common stock	(14)
Decrease due to higher repayments of long-term debt	(7)
Decrease in net receipts from settlement of acquired derivatives	(6)





	$	3,110

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

For the three months ended March 31, 2026, the Company had domestic pre-tax book income of $103 million and foreign pre-tax book loss of $20 million. As of December 31, 2025, the Company had cumulative U.S. federal NOL carryforwards of $6.6 billion, of which $5.1 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 $392 million, most of which do not have an expiration date. In addition to the above NOLs, NRG has a $58 million indefinite carryforward for interest deductions, as well as $288 million of tax credits, inclusive of $92 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 of up to $90 million in 2026. 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 months ended March 31, 2026.

As of March 31, 2026, the Company has $56 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 2022. 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 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 first quarter current and deferred taxes, however, there is no material impact to the income tax (benefit)/expense for the three months ended March 31, 2026.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of March 31, 2026 and December 31, 2025, NRG recorded a net deferred tax asset, excluding valuation allowance, of $1.8 billion and $2.0 billion, respectively. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of March 31, 2026 and December 31, 2025 as discussed below.

NOL Carryforwards — As of March 31, 2026, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.4 billion and $326 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 $104 million.

Valuation Allowance — As of March 31, 2026 and December 31, 2025, the Company’s tax-effected valuation allowance was $147 million and $150 million, respectively consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary differences.

Guarantor Financial Information

As of March 31, 2026, 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)	Three months ended March 31, 2026
Revenue(a)	$	8,995
Operating income(b)	116
Total other expense	(198)
Loss before income taxes	(82)
Net loss	(46)

(a)Intercompany transactions with Non-Guarantors of $3 million during the three months ended March 31, 2026

(b)Intercompany transactions with Non-Guarantors including cost of operations of $13 million and selling, general and administrative of $113 million during the three months ended March 31, 2026

The following table presents the summarized balance sheet information:


(In millions)	As of March 31, 2026
Current assets(a)	$	6,325
Property, plant and equipment, net	4,971
Non-current assets	22,063
Current liabilities(b)	10,691
Non-current liabilities	18,618

(a)Includes intercompany receivables due from Non-Guarantors of $159 million as of March 31, 2026

(b)Includes intercompany payables due to Non-Guarantors of $404 million as of March 31, 2026

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 March 31, 2026, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2026. 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, 2025(a)	$	397
Contracts realized or otherwise settled during the period	3
LSP Portfolio contracts acquired during the period	(96)
Other changes in fair value	(210)
Fair Value of Contracts as of March 31, 2026(a)	$	94

(a)As of December 31, 2025 and March 31, 2026, respectively, includes $484 million and $433 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


	Fair Value of Contracts as of March 31, 2026
(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	$	(99)	$	(17)	$	(4)	$	—	$	(120)
Level 2	(24)		19		9		(1)		3
Level 3	(158)		(82)		(4)		22		(222)
Total	$	(281)	$	(80)	$	1	$	21	$	(339)

(a)Excludes $433 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

The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or posted on the Company’s derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company’s portfolio. As discussed in Item 3, Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company’s portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG’s Risk Management Policy places a limit on one-day holding period VaR, which limits the Company’s net open position. As the Company’s trade-by-trade derivative accounting results in a gross-up of the Company’s derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG’s hedging activity. As of March 31, 2026, NRG’s net derivative asset was $94 million, a decrease to total fair value of $303 million as compared to December 31, 2025. This decrease was primarily driven by losses in fair value and the LSP 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 $951 million in the net value of derivatives as of March 31, 2026. 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 $956 million in the net value of derivatives as of March 31, 2026.

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 2025 Form 10-K. There have been no material changes to the Company’s critical accounting estimates since the 2025 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 2025 Form 10-K.

Commodity Price Risk

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

The following table summarizes average, maximum and minimum VaR for NRG’s commodity portfolio, calculated using the VaR model for the three months ended March 31, 2026 and 2025. The VaR increase is primarily due to the addition of new generation assets during the first quarter of 2026.


(In millions)	2026		2025
VaR as of March 31,	$	85	$	59
Three months ended March 31,
Average	$	89	$	54
Maximum	110		70
Minimum	57		47

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 $151 million, as of March 31, 2026, primarily driven by asset-backed and risk management 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

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	73	%
Financial institutions	27

Total as of March 31, 2026	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	70	%
Non-investment grade/Non-Rated	30
Total as of March 31, 2026	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 March 31, 2026, 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 $1.3 billion 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 $355 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2026.

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.

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 March 31, 2026, a 1% change in variable interest rates would result in a $66 million change in interest expense on a rolling twelve-month basis.

As of March 31, 2026, the fair value and related carrying value of the Company’s debt was $22.9 billion and $23.3 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company’s long-term debt as of March 31, 2026 by $905 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 March 31, 2026, 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 $397 million.

The Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the United States are translated into U.S. dollars using exchange rates effective during the respective period. As a result, the Company is exposed to movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and Australian dollars. A hypothetical 10% appreciation in major currencies relative to the U.S. dollar as of March 31, 2026 would have resulted in a decrease of $1 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 March 31, 2026 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 March 31, 2026, see Note 14, Commitments and Contingencies and Note 15, Regulatory Matters, to this Form 10-Q.

ITEM 1A — RISK FACTORS

During the three months ended March 31, 2026, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company’s 2025 Form 10-K.

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

Issuer Purchases of Equity Securities

The table below sets forth the information with respect to purchases made by or on behalf of NRG or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG’s common stock during the quarter ended March 31, 2026.


For the three months ended March 31, 2026	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)
Month #1
(January 1, 2026 to January 31, 2026)	656,900	$	151.93	656,900	$	3,207
Month #2
(February 1, 2026 to February 28, 2026)	490,000	$	162.90	490,000	$	3,127
Month #3
(March 1, 2026 to March 31, 2026)(d)	1,829,269	$	164.00	1,829,269	$	2,826

Total at March 31, 2026	2,976,169	$	161.16	2,976,169

(a)Includes share repurchases under the $3.7 billion share repurchase authorization and the $3.0 billion repurchase authorization. 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 and fees paid in connection with the share repurchases

(c)Includes commissions and fees paid in connection with the share repurchases

(d)The Company entered into a stock purchase agreement to repurchase 1,829,269 shares of NRG common stock from LS Power

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 March 31, 2026, 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

3/16/2026

Rule 10b5-1 Trading Arrangement

Up to 31,145 shares to be Sold

6/15/2026-9/16/2026

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

Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

(e)

On February 19, 2026, the Board of Directors of the Company adopted the NRG Energy, Inc. 2026 Long-Term Incentive Plan (the “2026 LTIP”), subject to approval by the Company’s stockholders. As reported in the Current Report on Form 8-K filed by the Company on May 1, 2026, at the Company’s 2026 annual meeting of stockholders held on April 30, 2026, the Company’s stockholders approved the 2026 LTIP. The aggregate number of shares of common stock of the Company available for issuance under the 2026 LTIP is 5,000,000 (less any shares underlying equity awards granted between March 3, 2026 and April 30, 2026 under the Company’s existing LTIPs).

The material features of the 2026 LTIP are described in the Company’s definitive proxy statement on Schedule 14A filed with the SEC on March 18, 2026, as supplemented on April 16, 2026. A copy of the 2026 LTIP was filed as Exhibit 10.1 to the Registration Statement on Form S-8 filed on April 30, 2026 and is incorporated herein by reference.

ITEM 6 — EXHIBITS

Number

Description

Method of Filing

4.1

Third Supplemental Indenture, dated April 28, 2026, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Trust Company Americas, as trustee, containing Form of 4.955% Senior Secured First Lien Notes due 2031.

Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on April 28, 2026.

4.2

Incorporated herein by reference to Exhibit 4.5 to the Registrant's current report on Form 8-K filed on April 28, 2026.

10.1

Sixteenth Amendment to Second Amended and Restated Credit Agreement, dated as of April 28, 2026, by and 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 April 28, 2026.

22.1

List of Guarantor Subsidiaries

Filed herewith.

31.1

Rule 13a-14(a)/15d-14(a) certification of Robert J . Gaudette .

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.