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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2025

— OR —


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __ to __

Commission File Number 001-38086

Vistra Corp.

(Exact name of registrant as specified in its charter)

Delaware

36-4833255

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

6555 Sierra Drive

Irving,

Texas

75039

(214)

812-4600

(Address of principal executive offices) (Zip Code)

(Registrant's telephone number, including area code)

Title of Each Class

Trading Symbol(s)

Name of Each Exchange on Which Registered

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

Common stock, par value $0.01 per share

VST

New York Stock Exchange

NYSE Texas

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicated by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

As of June 30, 2025, the last business day of Vistra Corp.'s most recently completed second fiscal quarter, the aggregate market value of the Vistra Corp. common stock held by non-affiliates of the registrant was $65,311,459,773 based on the closing sale price as reported on the New York Stock Exchange.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.


Class						Outstanding as of February 18, 2026
Common stock, par value $0.01 per share						336,954,256

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant's definitive Proxy Statement relating to its 2026 Annual Meeting of Stockholders are incorporated by reference in Part III of this annual report on Form 10-K.

TABLE OF CONTENTS

PAGE

Glossary of Terms and Abbreviations

iii

Forward-Looking Statements

vii

Industry and Market Information

Human Capital Resources

Environmental Regulations and Related Considerations

Corporate Information

Available Information

Item 1A.

RISK FACTORS

Item 1B.

UNRESOLVED STAFF COMMENTS

MINE SAFETY DISCLOSURES

PART II.

Item 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Item 6.

[RESERVED]

Item 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, AND RESULTS OF OPERATIONS

K ey Financial Results

B usiness Environment and Outlook

Noteworthy Developments

F actors Affecting Our Financial Condition and Results of Oper ations

Results of Operations

Liquidity and Capital Resources

Critical Accounting Estimates

Changes in Accounting Standards

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

R eport of Independent Registered Public Accounting Firm

Consolidated Statements of Operations

Consolidated Statements of Comprehensive Income (Loss)

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

Consolidated Statement of Changes in Equity

Notes to Consolidated Financial Statements:

1. Business and Significant Accounting Policies

7. Property, Plant, and Equipment

106


		8. Loss Events and Insurance Recoveries	107
		9. Goodwill and Identifiable Intangible Assets and Liabilities	110
		10. Collateral Financing Agreement with Affiliate	112
		11. Debt, Credit Facilities, and Financings	113
		12. Leases	122
		13. Derivatives	123
		14. Fair Value Measurements	128
		15. Asset Retirement Obligations	132
		16. Pension and Other Postretirement Employee Benefits (OPEB) Plans	133
		17. Stock-Based Compensation	138
		18. Commitments and Contingencies	140
		19. Equity	147
		20. Earnings Per Share	150
		21. Segment Information	150
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		154
Item 9A.	CONTROLS AND PROCEDURES		154
Item 9B.	OTHER INFORMATION		155
Item 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS		156
PART III.
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		157
Item 11.	EXECUTIVE COMPENSATION		157
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		157
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		157
Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES		157
PART IV.
Item 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		158
Item 16.	FORM 10-K SUMMARY		180
Signatures			181

GLOSSARY OF TERMS AND ABBREVIATIONS

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


Current and Former Related Entities:
Ambit Energy						Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit Energy), depending on context
Ambit Texas						Ambit Texas, LLC, a wholly owned subsidiary of Vistra
BCOP						BCOP Borrower LLC, a subsidiary of Vistra Zero
Dynegy						Dynegy Inc., and/or its subsidiaries, depending on context
Dynegy Energy Services						Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (each d/b/a Dynegy, Better Buy Energy, Brighten Energy, Honor Energy and True Fit Energy), indirect, wholly owned subsidiaries of Vistra, that are REPs in certain areas of MISO and PJM, respectively, and are engaged in the retail sale of electricity to residential and business customers
EFH Corp.						Energy Future Holdings Corp., a holding company and formerly the indirect parent of our predecessor
Energy Harbor						Energy Harbor Holdings LLC (formerly known as Energy Harbor Corp.), and/or its subsidiaries, depending on context
Homefield Energy						Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of MISO that is engaged in the retail sale of electricity to municipal customers
Lotus						Lotus Infrastructure Partners
Luminant						subsidiaries of Vistra engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management
Oncor						Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and formerly an indirect subsidiary of EFH Corp., that is engaged in regulated electricity transmission and distribution activities
Parent						Vistra Corp.
Public Power						Public Power, LLC (d/b/a Public Power), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers
TriEagle Energy						TriEagle Energy, LP (d/b/a TriEagle Energy, TriEagle Energy Services, Eagle Energy, Energy Rewards, Power House Energy and Viridian Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of ERCOT and PJM that is engaged in the retail sale of electricity to residential and business customers
TXU Energy						TXU Energy Retail Company LLC (d/b/a TXU), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
U.S. Gas & Electric						U.S. Gas and Electric, LLC (d/b/a USG&E, Illinois Gas & Electric and ILG&E), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers
Value Based Brands						Value Based Brands LLC (d/b/a 4Change Energy, Express Energy and Veteran Energy), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
Vistra						Vistra Corp., and/or its subsidiaries, depending on context
Vistra Intermediate						Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra
Vistra Operations						Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the issuer of certain series of notes (see Note 11 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
Vistra Vision						Vistra Vision LLC, an indirect subsidiary of Vistra
Vistra Zero						subsidiaries of Vistra engaged in the operation and development of renewables and energy storage assets
Vistra Zero Operating						Vistra Zero Operating Company, LLC, an indirect, wholly owned subsidiary of Vistra
Transmission System Operators:
CAISO						The California Independent System Operator

iii


ERCOT						Electric Reliability Council of Texas, Inc.
ISO-NE						ISO New England Inc.
MISO						Midcontinent Independent System Operator, Inc.
NYISO						New York Independent System Operator, Inc.
PJM						PJM Interconnection, LLC
Authoritative Organizations:
CFTC						U.S. Commodity Futures Trading Commission
DOE						U.S. Department of Energy
EPA						U.S. Environmental Protection Agency
FERC						U.S. Federal Energy Regulatory Commission
FTC						Federal Trade Commission
IEPA						Illinois Environmental Protection Agency
IPCB						Illinois Pollution Control Board
IRS						U.S. Internal Revenue Service
MSHA						U.S. Mine Safety and Health Administration
NERC						North American Electric Reliability Corporation
NRC						U.S. Nuclear Regulatory Commission
OSHA						U.S. Occupational Safety and Health Administration
PUCT						Public Utility Commission of Texas
RCT						Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas, and has jurisdiction over oil and natural gas exploration and production, permitting and inspecting intrastate pipelines, and overseeing natural gas utility rates and compliance
SEC						U.S. Securities and Exchange Commission
TCEQ						Texas Commission on Environmental Quality
Rules and Regulations:
CAA						Clean Air Act
ERISA						Employee Retirement Income Security Act of 1974
Exchange Act						Securities Exchange Act of 1934, as amended
IRA						Inflation Reduction Act of 2022
OBBBA						One Big Beautiful Bill Act
Securities Act						Securities Act of 1933, as amended
General Terms:
2024 Form 10-K						Vistra's annual report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 28, 2025
ARO						asset retirement and mining reclamation obligation
BCOP Credit Agreement						credit agreement, dated as of December 16, 2024 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among BCOP, the lenders and issuing banks party thereto, the administrative agent, and collateral agent and the other parties named therein
Board						Vistra Corp.'s Board of Directors
CCGT						combined cycle natural gas turbine
CCR						coal combustion residuals
CME						Chicago Mercantile Exchange
CO2						carbon dioxide
CT						combustion turbine
EBITDA						earnings (net income) before interest expense, income taxes, depreciation and amortization


Effective Date						October 3, 2016, the date our predecessor completed its reorganization under Chapter 11 of the U.S. Bankruptcy Code
ESPP						Vistra Corp. 2025 Employee Stock Purchase Plan
ESS						energy storage system
Fitch						Fitch Ratings Inc. (a credit rating agency)
GAAP						generally accepted accounting principles
GHG						greenhouse gas
GWh						gigawatt-hours
Heat Rate						Heat Rate is a measure of the efficiency of converting a fuel source to electricity
ISO						independent system operator
ITC						investment tax credit
kW						kilowatt
load						demand for electricity
LTSA						long-term service agreements for plant maintenance
Market Heat Rate						Market Heat Rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier (generally natural gas plants), by the market price of natural gas.
MMBtu						million British thermal units
Moody's						Moody's Investors Service, Inc. (a credit rating agency)
MW						megawatts
MWh						megawatt-hours
NOX						nitrogen oxide
NYMEX						the New York Mercantile Exchange, a commodity derivatives exchange
NYSE						New York Stock Exchange
OPEB						postretirement employee benefits other than pensions
PrefCo Preferred Stock Sale						as part of the tax-free spin-off from EFH Corp. executed pursuant to the Third Amended Joint Plan of Reorganization filed by the parent company of our predecessor in August 2016 and confirmed by the U.S. Bankruptcy Court for the District of Delaware in August 2016 solely with respect to our predecessor (Plan of Reorganization) on the Effective Date, the contribution of certain of the assets of the predecessor and its subsidiaries by a subsidiary of TEX Energy LLC to Vistra Preferred Inc. (PrefCo) in exchange for all of PrefCo's authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share
PTC						production tax credit
REP						retail electric provider
RTO						regional transmission organization
S&P						Standard & Poor's Ratings (a credit rating agency)
Series A Preferred Stock						Vistra's 8.0% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
Series B Preferred Stock						Vistra's 7.0% Series B Fixed-Rate Reset Cumulative Green Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
Series C Preferred Stock						Vistra's 8.875% Series C Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
SG&A						selling, general, and administrative
SO2						sulfur dioxide
SOFR						Secured Overnight Financing Rate, the average rate at which institutions can borrow U.S. dollars overnight while posting U.S. Treasury Bonds as collateral
ST						steam turbine
Tax Matters Agreement						Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and EFH Merger Co. LLC


TRA						Amended and Restated Tax Receivable Agreement, containing certain rights (TRA Rights) to receive payments from Vistra related to certain tax benefits, including benefits realized as a result of certain transactions entered into at the emergence of our predecessor from reorganization under Chapter 11 of the U.S. Bankruptcy Code
TWh						terawatt-hours
U.S.						United States of America
Vistra Operations Commodity-Linked Credit Agreement						credit agreement, dated as of February 4, 2022 (as amended, restated, amended and restated, supplemented, and/or otherwise modified from time to time) by and among Vistra Operations, Vistra Intermediate, the lenders party thereto, the other credit parties thereto, the administrative agent, the collateral agent, and the other parties named therein
Vistra Operations Credit Agreement						credit agreement, dated as of October 3, 2016 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among Vistra Operations, Vistra Intermediate, the lenders party thereto, the letter of credit issuers party thereto, the administrative agent, the collateral agent, and the other parties named therein
Vistra Operations Credit Facilities						Vistra Operations senior secured financing facilities
Vistra Zero Credit Agreement						credit agreement, dated as of March 26, 2024 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among Vistra Zero Operating, the lenders party thereto, the administrative agent, and collateral agent, and the other parties named therein

FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains forward-looking statements that involve risk and uncertainties. All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including (without limitation) such matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments, and the growth of our businesses and operations, including potential transactions with large load facilities at our nuclear and natural gas plants (often, but not always, through the use of words or phrases such as "intends," "plans," "potential," "will likely," "unlikely," "believe," "expect," "anticipated," "estimate," "should," "could," "may," "projection," "forecast," "target," "goal," "objective," and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and risks that could cause our actual results to differ materially from those projected in or implied by such forward looking statement. Any such forward-looking statement is qualified in its entirety by reference to the discussion in Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations in this annual report on Form 10-K.

Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events or circumstances. New factors emerge from time to time, and it is not possible for us to predict them. In addition, we may be unable to assess the impact of any such event or condition or the extent to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.

INDUSTRY AND MARKET INFORMATION

Certain industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the environmental regulatory bodies of states in which we operate, and NYMEX. We did not commission any of these publications, reports or other sources. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Industry publications, reports, and other sources generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies, publications, reports, and other sources is reliable, we have not independently investigated or verified the information contained or referred to therein and make no representation as to the accuracy or completeness of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used throughout this report involve risks and uncertainties and are subject to change based on various factors.

vii

VISTRA CORP.

PART I

Item 1.BUSINESS

References in this report to "we," "our," "us," and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary of Terms and Abbreviations for defined terms.

General

Vistra is an integrated retail electricity and power generation company that provides essential power resources to customers, businesses, and communities from California to Maine. We combine an innovative, customer-centric approach to retail sales with safe, reliable, diverse, and efficient power generation. Our integrated power generation and wholesale operation allows us to efficiently obtain the electricity needed to serve our customers at the lowest cost. The integrated model enables us to structure products and contracts in a way that offers significant value compared to stand-alone retail electric providers.

The Company brings its products and services to market in 18 states and the District of Columbia, including all major competitive wholesale power markets in the U.S. We serve approximately 5 million residential, commercial, and industrial retail customers with electricity and natural gas. Our generation fleet totals approximately 44,000 megawatts of generation capacity powered by a diverse portfolio, including natural gas, nuclear, coal, solar, and battery energy storage facilities.

Market Discussion

The operations of Vistra are aligned into five reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. Our Texas, East, and West segments include our electricity generation operations, and our Asset Closure segment is engaged in the decommissioning and reclamation of retired generation facilities, including mines, and battery removal and remediation activities. See Note 21 to the Financial Statements for additional information.

Retail Operations

Vistra is one of the largest competitive residential retail electricity providers in the U.S. Our retail operations are engaged in retail sales of electricity, natural gas, and related services to approximately 5 million customers. Substantially all of our retail activities are conducted by TXU Energy, Ambit Energy, Dynegy Energy Services, Homefield Energy, Energy Harbor, and U.S. Gas & Electric across 16 U.S. states and the District of Columbia. The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 2.6 million customers.

Our TXU Energy brand, which has been used to sell electricity to customers in the competitive retail electricity market in Texas for over 20 years, is registered and protected by trademark law. We also own the trade names for Ambit Energy, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power, and U.S. Gas & Electric.

We believe that we have differentiated ourselves by providing a distinctive customer experience predicated on delivering reliable and innovative power products and solutions to our customers, including 100% wind and solar options, as well as thermostats, dashboards, and other programs designed to encourage reduced electricity consumption and increased energy efficiency. Our distinctive power products give our customers choice, convenience, and control over how and when they use electricity and related services.

Electricity Generation Operations

Vistra is one of the largest competitive power generators in the U.S. as measured by MWh of generation capacity. At December 31, 2025, our generating capacity was powered by the following fuels and technologies:


Primary Fuel	Technology	Net Capacity (MW)	% of Net Capacity
Natural Gas	CCGT, CT or ST	26,989	62%
Coal	ST	8,743	20%
Uranium	Nuclear	6,448	15%
Renewable	Solar/Battery	1,274	3%
Fuel Oil	CT	187	—%
Total		43,641	100%

VISTRA CORP.

Our natural gas-fueled generation fleet is comprised of 28 CCGT generation facilities totaling 22,167 MW and 12 peaking generation facilities totaling 4,822 MW. We satisfy our fuel requirements at these facilities through a combination of spot market and near-term purchase contracts. Additionally, we have near-term natural gas transportation agreements and natural gas storage agreements in place to ensure fleet reliability.

Our coal/lignite-fueled generation fleet is comprised of seven generation facilities totaling 8,743 MW of generation capacity. We meet our fuel requirements at our coal-fueled generation facilities in PJM and MISO with coal purchased from multiple suppliers under contracts of various lengths and transported to the facilities by either railcar or barges. We meet our fuel requirements in ERCOT using lignite that we mine at our generation facilities and coal purchased and transported by railcar.

We own and operate six nuclear generation units at four different facilities:

Unit

ISO

Net Capacity (MW)

Refueling Outage Frequency

License Expiration Date

Comanche Peak Unit 1

ERCOT

1,200

18 Months

2050

Comanche Peak Unit 2

ERCOT

1,200

18 Months

2053

Beaver Valley Unit 1

PJM

939

18 Months

2036

Beaver Valley Unit 2

PJM

933

18 Months

2047

Perry

PJM

1,268

24 Months

2046

Davis-Besse

PJM

908

24 Months

2037

Total

6,448

Nuclear units are generally operated at full capacity. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur during the spring or fall off-peak demand periods. While one unit is undergoing a refueling outage at dual-unit facilities, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification, and testing activities are completed that cannot be accomplished when the unit is in operation.

We have nuclear fuel contracted to support all of our refueling needs through 2030. We do not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion, enrichment, and fabrication services in the foreseeable future. We continue to take affirmative action by building strategic inventory and deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facilities through potential Russian supply disruption.

Our generation operations by segment are represented in the following table:


Segment	Net Capacity (MW)	% of Net Capacity	ISO/RTO
Texas	19,858	46%	ERCOT
East	22,254	51%	PJM, ISO-NE, MISO, and NYISO
West	1,529	3%	CAISO
Total	43,641	100%

Wholesale Operations — Our wholesale commodity risk management group is responsible for dispatching our generation fleet in response to market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleet production with our retail customer and wholesale sales opportunities. Market demand, also known as load, faced by electric power systems, such as those we operate in, varies from moment to moment as a result of changes in business and residential demand, which is often driven by weather. Unlike most other commodities, the production and consumption of electricity must remain balanced on an instantaneous basis. There is a certain baseline demand for electricity across an electric power system that occurs throughout the day, which is typically satisfied by baseload generation units with low variable operating costs. Baseload generation units can also increase output to satisfy certain incremental demand and reduce output when demand is unusually low. Intermediate/load-following generation units, which can more efficiently change their output to satisfy increases in demand, typically satisfy a large proportion of changes in intraday load as they respond to daily increases in demand or unexpected changes in supply created by reduced generation from renewable resources or other generator outages. Peak daily loads may be satisfied by peaking units. Peaking units are typically the most expensive to operate, but they can quickly start up and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load following units, and peaking units are dispatched into the ISO/RTO grid in order from lowest to highest variable cost. Price formation is typically based on the highest variable cost unit that clears the market to satisfy system demand at a given point in time.

VISTRA CORP.

Our commodity risk management group enters into electricity, natural gas, and other commodity derivative contracts to reduce exposure to price fluctuations with the goal of reducing volatility of future revenues and fuel costs for our generation facilities and purchased power costs for our Retail segment.

Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) — ISOs and RTOs manage the transmission infrastructure and markets across regions, separate from our operations. They dispatch generation facilities, ensuring efficient and reliable transmission system operation. ISOs/RTOs administer short-term energy and ancillary service markets, typically day-ahead and real-time, and some also manage long-term planning reserves through various capacity markets. They impose bid and price limits in wholesale power markets. NERC regions, which are responsible for enforcing mandatory electric reliability standards applicable to generation owners and operators, and ISOs/RTOs often have different geographic footprints, and while there may be geographic overlap between NERC regions and ISOs/RTOs, their respective roles and responsibilities do not generally overlap. An independent market monitor continually monitors ISO and RTO markets to ensure a robust, competitive market and to identify improper behavior by any entity.

In centrally dispatched market structures (e.g., ERCOT, PJM, ISO-NE, NYISO, MISO, CAISO), all generators receive the same price for energy based on the bid price of the last MWh needed to balance supply and demand. Prices vary within different zones due to transmission losses and congestion. For example, if a less efficient natural gas unit is needed to meet demand, its offer price sets the market clearing price for all dispatched generation in that market, regardless of other units' offer prices. Generators receive the location-based marginal price for their output.

ERCOT — ERCOT is an ISO that manages the flow of electricity from approximately 83,707 MW of 2025 peak demand to approximately 27 million Texas customers, representing approximately 90% of the state's electric load.

Transactions in ERCOT take place in two key markets: the day-ahead market and the real-time market. The day-ahead market is a voluntary, financial electricity market conducted the day before each operating day in which generators and purchasers of electricity may bid for one or more hours of electricity supply or consumption. The real-time market is a physical market in which electricity and ancillary services awards are determined and priced in five-minute intervals based on the least-cost dispatch respecting transmission constraints. The day-ahead market provides market participants with visibility into where prices are expected to clear, and the prices are not impacted by subsequent events. Conversely, the real-time market exposes purchasers to the risk of transient operational events and price spikes. These two markets allow market participants to manage their risk profile by adjusting their participation in each market.

Unlike regions that maintain minimum planning reserve margins through regulated resource planning, mandatory capacity requirements, or centralized capacity markets, ERCOT relies primarily on energy-market price signals to incentivize investment in and availability of generation resources. Prices in ERCOT are determined through marginal pricing, meaning the cost of the last resource needed to balance supply and demand establishes the market price for all dispatched generation at a given location, subject to transmission congestion and losses. Outside of periods of scarcity, wholesale electricity prices in ERCOT typically reflect the relative amount of renewable generation on the system and the associated need for thermal generation. When renewable generation is abundant relative to demand, prices are set by either renewable resources or low-cost thermal resources. When renewable generation is low relative to demand, prices are set by natural gas‑fueled generation facilities or energy storage.

ERCOT's Operating Reserve Demand Curve (ORDC) was a scarcity pricing mechanism under which wholesale electricity prices in the real-time market would increase as available operating reserves declined, historically allowing prices to rise to the system-wide offer cap during periods of low reserves. With the implementation of real-time co-optimization in December 2025, the ORDC was replaced by individual ancillary service demand curves (ASDCs) that are designed to mimic the operation of the ORDC.

Because ERCOT has one of the highest concentrations of wind and solar capacity generation and battery energy storage among U.S. markets, the ERCOT market is more susceptible to fluctuations in wholesale electricity supply due to intermittent wind and solar production and state of charge limitation from battery energy storage. Periods of extreme weather, including prolonged high temperatures during summer months or severe cold during winter months, can materially increase electricity demand and reduce available generation, particularly when combined with variability in renewable output, making ERCOT more vulnerable to periods of generation scarcity. Large load flexibility during high demand periods could be an important mechanism to maintain reliability. In 2025, the Texas legislature passed Senate Bill 6 (SB 6) that requires certain co-located large loads and some front-of-the-meter large loads to provide load flexibility during emergencies. SB 6 requires these load curtailments to not interfere with energy price formation.

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ERCOT uses ancillary services to maintain system reliability, including regulation service, responsive reserve service, ERCOT contingency reserve service, and non-spinning reserve service. These ancillary services are provided by generators, energy storage, and qualified loads to help maintain the stable voltage and frequency requirements of the transmission system and to create operating reserves to manage load and intermittent resource output uncertainty. Under real-time co-optimization, as energy prices rise ERCOT will go short on ancillary services based on the ASDCs, converting that reserve capacity to energy and reflecting that scarcity value in energy prices.

ERCOT is developing a proposed ancillary service, the Dispatchable Reliability Reserve Service (DRRS), to address inter-hour operations challenges, reduce the use of reliability unit commitments, and support the reliability standard. While stakeholders have disagreed on the degree to which DRRS should support the reliability standard, in December 2024, the PUCT expressed a preference to have ERCOT develop DRRS so it can both address operational issues and be flexible to help address resource adequacy issues without significant additional effort. ERCOT is continuing work on DRRS, and it has not been implemented and remains subject to ongoing stakeholder review and regulatory approval.

ERCOT also applies safeguards designed to moderate the duration and impact of sustained high prices. The "peaker net margin" is based on revenues a hypothetical unhedged peaking unit with perfect commitment would collect in the market. If the peaker net margin exceeds a threshold of three-times the Cost of New Entry (CONE) reference price, the maximum point on each ASDC is reduced to the low system-wide offer cap of $2,000/MWh for the remainder of the calendar year. Additionally, the PUCT approved an Emergency Pricing Program that temporarily lowers the system-wide offer cap to $2,000/MWh if prices have been at the cap for 12 hours in a rolling 24-hour period.

PJM — PJM is an RTO that manages the flow of electricity from approximately 160,709 MW of peak 2025 demand to approximately 67 million customers in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

Like ERCOT, PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing a locational marginal pricing (LMP) methodology which calculates a price for every generator and load point within PJM. PJM operates day-ahead and real-time markets into which generators can bid to provide energy and ancillary services. Offers into the energy markets are capped at $1,000/MWh unless a resource can cost justify an offer above $1,000/MWh. Cost-justified offers between $1,000/MWh and $2,000/MWh can set the energy price. Cost-justified energy offers above $2,000/MWh cannot set the energy price, but resources will get cost recovery for verified costs above $2,000/MWh. PJM also administers a forward capacity auction, the Reliability Pricing Model (RPM), which establishes a long-term market for capacity. The price of capacity is determined in part by a capacity demand curve that is reviewed every four years. The capacity demand curve establishes a maximum price for capacity. PJM proposed and FERC approved an administrative price ceiling below the maximum price for capacity, for capacity delivery years 2026-2027 and 2027-2028. In February 2026, PJM announced that it would propose to extend the administrative price cap for delivery years 2028-2029 and 2029-2030. That proposal is subject to FERC approval. The Trump administration and PJM state governors have proposed that PJM conduct a reliability backstop auction on a one-time basis in September 2026 to procure new generation to close the resource adequacy gap. PJM is working with stakeholders to develop the design for the reliability backstop auction and expects to file the design with FERC by May 2026. Any design will be subject to FERC approval. We have participated in RPM auctions up to and including PJM's planning year 2027-2028, which ends May 31, 2028. We also enter into bilateral capacity transactions, with other PJM market participants, including load-serving entities and generation owners, to manage capacity obligations, pricing exposure, and portfolio risk.

In December 2025, FERC determined that PJM needs to update its market rules to facilitate large loads co-locating with generation resources. These new rules require PJM to develop new transmission service products that allow co-located large loads to select a transmission service that matches the co-located large loads actual use of the transmission system. These new rules also require co-located loads to pay for some ancillary services on a gross basis. PJM is working with stakeholders to develop these new transmission services. Overall, we believe these new rules will remove regulatory uncertainty for co-location arrangements.

ISO-NE — ISO-NE is an ISO that manages the flow of electricity from approximately 30,600 MW of winter generation capacity to approximately 15 million customers in the states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island, and Maine.

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ISO-NE dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the locations in ISO-NE and are largely influenced by transmission constraints, the cost of one of the ancillary services, and fuel supply.

ISO-NE's day-ahead ancillary services market structures each ancillary service as an option contract so that resources selling day-ahead ancillary services settle against a real-time strike price, thereby providing strong incentives for those resources to be capable of providing energy in real time. In addition, the cost of Energy Imbalance Reserves, the day-ahead ancillary service designed to ensure adequate physical supply to meet forecast demand, is added to the energy price paid to all physical resources with a day-ahead energy schedule.

ISO-NE offers the Forward Capacity Market where capacity prices are determined through auctions currently run three years prior to the capacity delivery year. In January 2026, ISO-NE submitted to FERC a proposal to transition to a prompt capacity market for the delivery year starting in June 2028. That filing is pending FERC action. Performance incentive rules have the potential to increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level.

NYISO — NYISO is an ISO that manages the flow of electricity from approximately 37,700 MW of installed summer generation capacity to approximately 20 million New York customers.

NYISO dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the regional zones and locations in the NYISO and are largely influenced by transmission constraints and fuel supply. NYISO offers the Installed Capacity Market, a forward capacity market where capacity prices are determined through auctions. Strip auctions occur one to two months prior to the commencement of a six-month seasonal planning period. Subsequent auctions provide an opportunity to sell excess capacity for the balance of the seasonal planning period or the upcoming month. Due to the short-term nature of the NYISO-operated capacity auctions and a relatively liquid bilateral market for NYISO capacity products, we sell a significant portion of our NYISO capacity through bilateral transactions. The balance is cleared through the seasonal and monthly capacity auctions.

MISO — MISO is an RTO that manages the flow of electricity from approximately 207,000 MW of installed generation capacity to approximately 45 million customers in all or parts of Iowa, Minnesota, North Dakota, Wisconsin, Michigan, Kentucky, Indiana, Illinois, Missouri, Arkansas, Mississippi, Texas, Louisiana, Montana, South Dakota, and Manitoba, Canada.

MISO dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the regional zones and locations in MISO and are largely influenced by transmission constraints and fuel supply.

MISO administers Planning Resource Auctions to procure capacity for future planning periods. These auctions were historically conducted on an annual basis and have transitioned to a seasonal structure. We participate in these auctions with capacity that has not been committed through bilateral or retail transactions. We also participate in MISO's annual and monthly financial transmission rights auctions to manage exposure to transmission congestion, as reflected in the congestion component of locational marginal price differentials between points on the transmission grid.

CAISO — CAISO is an ISO that manages the flow of electricity to approximately 32 million customers primarily in California, representing approximately 80% percent of the state's electric load.

Energy is priced in CAISO utilizing an LMP methodology. The capacity market is comprised of Generic, Flexible, and Local Resource Adequacy (RA) Capacity, which is administered by the California Public Utilities Commission (CPUC). Unlike other centrally cleared capacity markets, the resource adequacy markets in California are primarily bilaterally traded markets. Mechanisms to trade RA include through (i) the CPUC central procurement entity which runs a pay-as-bid auction for Local RA Capacity, (ii) a voluntary capacity auction run by CAISO for annual, monthly, and intra-month procurement to cover for deficiencies in the market, and (iii) the voluntary Competitive Solicitation Process, which is a modification to the Capacity Procurement Mechanism (CPM).

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Competition

Competition in the markets in which we operate is impacted by electricity and fuel prices, congestion along the power grid, subsidies provided by state and federal governments for new and existing generation facilities, including renewables generation and battery ESS, new market entrants, construction of new generation assets, technological advances in power generation, the actions of environmental and other regulatory authorities, and other factors. We primarily compete with other electricity generators and retailers based on our ability to generate electric supply, market and sell electricity at competitive prices, and efficiently utilize transportation from third-party pipelines and transmission from electric utilities to deliver electricity to end-users. Competitors in the generation and retail power markets in which we participate include numerous regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities, independent power producers, REPs, and other energy marketers. See Item 1A. Risk Factors for additional information concerning the risks faced with respect to the markets in which we operate.

Business Strategy

Vistra is one of the largest producers of power in deregulated markets in the U.S. with annual expected generation of over 230 TWh as of December 31, 2025.

Vistra is guided by four core principles:

•We do business the right way. Every decision we make and action we take will be a testament to the utmost integrity and compliance. Conducting our daily activities within the laws, regulations, and rules is not an option we choose but rather the way we do business that is ingrained in our culture.

•We work as a team. We work together on everything we do to support the success of the Company. Collaboration, information sharing, and cross-functional teamwork are fundamental to how we conduct our day-to-day activities.

•We compete to win. We have an unmatched work ethic, an analysis-driven and disciplined culture, and strong leadership and decision-making throughout the organization.

•We care about our key stakeholders. We care about our employees, our customers, and the communities where we live and do business. We will maintain productive and respectful relationships with our elected officials, regulators, and community leaders. We strive to achieve the full value of our enterprise for our investors.

To align with our four core principles, our focus is on the execution of our strategic priorities as follows:

Long-term, attractive earnings profile through the integrated business model. Our integrated business model distinguishes us from our electricity competitors as it combines our reliable and efficient diversified generation fleet totaling approximately 44,000 MW of capacity, with our commercial operations, including commodity risk management capabilities, and our best-in-class retail energy platform. We believe integrating retail with power generation stands as a fundamental competitive advantage that mitigates the impact of commodity price fluctuations and enhances the stability and predictability of our cash flows. Further, execution of large load offtake opportunities, including under long-term power purchase or offtake agreements, underwrite higher base profitability in the future.

Disciplined capital allocation. We strive to make thoughtful decisions when allocating our free cash flow to balance growth opportunities with returning capital to our stakeholders through share repurchases, dividends, and debt reduction.

Maintaining a resilient balance sheet. We seek to manage our financial leverage by maintaining a strong balance sheet which ensures our access to diverse sources of liquidity. We believe this provides financial flexibility for our capital allocation decisions, including executing on organic growth opportunities, engaging in mergers and acquisitions, opportunistic debt reduction, or returning capital to our stockholders.

Strategic energy transition that supports the reliability, affordability, and sustainability of the electric grid. As one of the largest electricity generators in the U.S., Vistra has led the way in decarbonization efforts and is committed to sustainability, setting aggressive targets, and transitioning our fleet to low-to-no carbon resources, all while balancing our obligations to our stakeholders. While the way we generate electricity may be changing, our essential role in providing reliable and affordable electricity is not.

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Human Capital Resources

Vistra's approach to human capital management, like every other decision we make and action we take, is guided by our core principles. These principles apply to all employees, suppliers, and contractors and guide how we interact with our partner companies, communities, the environment and all other stakeholders. We aim to conduct all aspects of our business in accordance with these core principles.

Vistra believes our most valuable asset is our talented, dedicated, and dynamic group of employees who work together to achieve our objectives, and our top priority is ensuring their safety. As of December 31, 2025, we had approximately 6,390 full-time employees, including approximately 1,860 employees under collective bargaining agreements.

Safety

Vistra's mindset around safety is exemplified by our motto: Best Defense. Everyone wins. No one gets hurt. Our safety culture revolves around people and human performance. We place a high importance on continuous improvement, along with a keen focus on numerous learning and error-prevention tools. To facilitate a learning environment, our various operating plants share their investigations and learnings of all safety events with all operations employees on weekly calls. The information is presented by front-line employees and supported by management. The lessons from each event are shared across the fleet to prevent similar incidents at other locations. All personnel at Vistra locations are encouraged to be actively involved in the safety process. Managers are required to participate in safety engagements with staff to enable constant communication and sustained interaction. In 2025, the generation fleet conducted more than 99,000 leadership safety engagements across the fleet continuing our employee driven safety program focused on engagement of all employees.

Our focus on reducing the severity of injuries for both our employees and contractors who work with us has shown positive results. Since the implementation of our Best Defense safety program, the number of serious injuries or fatalities has decreased significantly. Although we do not focus on recordable incidents, our Total Recordable Incident rate (TRIR) for company employees was 0.52, in the top quartile as compared to the Edison Electric Institute (EEI) 2024 Total Company Injury Data for companies of comparable size. We encourage near-miss reporting and review of events to promote a learning environment. In 2025, safety learning calls were held every week where near-miss and safety events were reviewed by our operating teams to promote learning across the fleet.

All Vistra employees are covered by our safety program. Corporate and retail employees are required to complete periodic training on safety topics through our online learning management system. Employees who are located at a power plant are required to complete trainings based on job function, which is also tracked through our central learning management system. In addition, the Company engages an independent third-party conformity assessment and certification vendor to manage adherence to our safety standards for all vendors and contractors who work at our plants. In addition, we work closely with our suppliers and contractors to ensure our safety practices are upheld.

All of our power plant facilities have effective health and safety programs and comply with OSHA regulations. In addition to compliance, our generation fleet has a total of 14 plants that have been awarded the Voluntary Protection Program (VPP) Star designation by the OSHA for superior demonstration of effective safety and health management systems and for maintaining injury and illness rates below the national averages for our industry. Our Masspower generation facility completed a VPP reevaluation and was recommended to continue as VPP Star in 2025. Our Masspower generation facility has been in the VPP Star program continuously since 1997. Our Fayette and Pleasants generation facilities submitted new applications for VPP status in 2025 and await evaluation from OSHA. VPP Star status is the highest designation of OSHA's Voluntary Protection Programs. The achievement recognizes employers and workers who have implemented effective safety and health management systems and maintain injury and illness rates below national Bureau of Labor Statistics (BLS) averages for their respective industries. These sites are self-sufficient in their ability to control workplace hazards and are reevaluated every three to five years. Additionally, 32 of our power plants and mine locations have adopted a proactive Behavior Based Safety approach to safety which focuses on identifying and providing feedback on at-risk behaviors observed.

Our People

Vistra aims to be a workplace of choice, and that means fostering a culture of teamwork that recognizes the value that each employee brings. Our workforce comes from the same communities we serve, bringing a range of perspectives, backgrounds, experiences, and expertise. Creating and maintaining an environment where our employees are able to do their best work and are appreciated for their contributions enhances our ability to recruit and retain the best talent in the marketplace.

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Vistra invests in the communities where our employees and customers live and work. This investment is through both corporate giving and volunteerism. Employees have ample opportunities to give back through corporate initiatives like our Trees For Growth tree-planting program and our seasonal Beat the Heat & Winter Warmth initiatives, along with other employee-led initiatives like Energy in Action, and collaborations with many community agencies across the country, such as United Way. Another way we engage with our communities is through our supply chain initiative, which seeks to create a dynamic supply chain that identifies suppliers of all sizes and across our markets that are able to provide quality products and services to the business.

Training and Development

We believe the development of employees at all levels is critical to Vistra's current and future success. We have launched key programs to develop leaders at all levels of the organization. We offer a variety of courses and programs targeted from front-line supervisors to senior leaders at Vistra. Each leader may select development opportunities based on their individualized needs. Vistra's Essentials of Leadership provides new managers with skills to lead organizations in situational leadership, business acumen, and exposes them to best practices from across the Company. We continue to evaluate and refine our programs as the development needs of our employees change. In 2025 we created new content to develop executive presence and communication for leaders. We have a continued focus on providing targeted development to grow leaders internally and build a pipeline for succession planning.

Vistra also provides many other training and development programs to help grow and develop employees at every level, including online learning platform courses, learning management system courses, recorded webinars and presentations, self-paced development and employee-specific skill training. The Vistra Learning Community is our online platform that strategically supports employees in completing thousands of hours of professional training to support continuing education requirements for their respective professional licenses, including accounting, legal and nuclear. In 2025, Vistra continued its formal mentoring program available to all employees to focus on topics like organizational knowledge, career development, individual development, collaboration and leadership. Over 260 employees participated in 2025. In addition, all full-time employees, other than those in a collective bargaining unit, receive a formal performance review guiding development and improving results of the business.

Employee Benefits

Maintaining attractive benefits and pay are important for recruiting and retaining talent. We are committed to maintaining an equitable compensation structure, including performing annual salary reviews by employee category level within significant locations of operations. Eligible full- and part-time employees are provided access to medical, prescription drug, dental, vision, life insurance, accidental death and dismemberment, long-term disability coverage, accident coverage, critical illness coverage and hospital indemnity coverage. Regular full-time employees are eligible for short-term disability benefits, and all employees are eligible for the employee assistance program, parental leave, maternity leave and a 401(k) plan through which the Company matches employee contributions up to 6%.

Wellness

We believe a healthy workforce leads to greater well-being at work and at home. To help keep our workforce healthy, we offer access to on-site medical clinics at five locations. Our healthcare plans are also designed to reward employees for getting annual physicals, age and gender health screenings and immunizations. In addition, our employee medical plans promote mental health and emotional wellness and offer resources for employees seeking assistance. Fitness centers in multiple facilities offer cardio equipment, a selection of free weights and exercise mats. Our employee-led wellness team engages our people to get active and support causes that promote healthy living. With support from the Company, the wellness team covers the registration costs for employees to participate in running and cycling events throughout the year.

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Environmental Regulations and Related Considerations

We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental regulatory bodies of states in which we operate. The EPA has finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities. However, in January 2025, President Trump issued a series of executive orders, including an order titled Unleashing American Energy (the Order) that ordered that all federal agencies are to review all existing regulations, orders, and other actions for consistency with the administration's policy goals, and develop an action plan within 30 days to resolve any policy inconsistencies. The Order requires the EPA to review the GHG, CSAPR, Legacy CCR, and ELG rules discussed below. Additionally, the Order states the U.S. Attorney General may request a stay of the litigation involving these rules while the EPA conducts its reviews. In addition to that Order, in April 2025, President Trump issued a series of additional executive orders on energy and deregulation priorities for his administration. We will monitor implementation and any agency actions related to those and other executive orders. See Item 1A. Risk Factors and Note 18 to the Financial Statements for additional information.

Climate Change

There is continuing interest from our stakeholders domestically and internationally on global climate change and how GHG emissions, such as CO2, contribute to global climate change. GHG emissions from the combustion of fossil fuels, primarily by our coal-fueled-generation plants as well as our natural gas-fueled generation plants represent the substantial majority of our total GHG emissions. CO2, methane and nitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions. We estimate that our generation facilities produced approximately 102 million short tons of CO2 in the year ended 2025. Vistra's carbon intensity for power generation improved from 0.48 short tons of CO2 per MWh in 2024 to 0.47 short tons of CO2 per MWh in 2025.

To manage our environmental impact from our business activities and reduce our emissions profile, Vistra set emissions reduction targets. Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO2 equivalent emissions by 2030 as compared to a 2010 baseline with a long-term goal to achieve net-zero carbon emissions by 2050, assuming necessary advancements in technology and supportive market constructs and public policy. Since 2010, Vistra has retired more than 15,100 MW of coal and natural gas power plants resulting in a 46% reduction in CO2 emissions, a 64% reduction in NOX emissions, and an 88% reduction in sulfur dioxide (SO2) emissions through year-end 2025, compared to a 2010 baseline. Vistra also has targets validated through the Science Based Targets initiative (SBTi). Our SBTi validated targets are to reduce absolute scope 1 and 2 GHG emissions 58% by 2028 from a 2018 base year, reduce absolute scope 1 and 3 GHG emissions from all sold electricity 58% within the same timeframe, and reduce absolute scope 3 GHG emissions from use of sold products 42% within the same timeframe.

The evolution of our generation portfolio is focused on ensuring reliability and affordability in the markets we serve with an emphasis on resilient dispatchable assets complemented by zero-carbon assets. We seek to serve our customers through a variety of generation sources, including efficient natural gas units, nuclear generation, renewables, and battery ESS, while we also continuously explore new technologies with lower carbon footprints.

We have already taken or announced significant steps to transform our generation portfolio with the goal of maintaining reliability while also reducing the emissions intensity of our generation fleet, including:

•Acquisition of Nuclear Generation Facilities — In 2024, we acquired Energy Harbor, including 4,048 MW of nuclear generation facilities in PJM.

•Acquisition of Natural Gas Generation Facilities — In 2025, we acquired 2,557 MW of natural gas generation facilities in Delaware and Pennsylvania (PJM), Rhode Island (ISO-NE), New York (NYISO), and California (CAISO).

•Re-powered generation assets — We intend to repower the Coleto Creek Power Plant in Texas and the Miami Fort Power Plant in Illinois to natural-gas fueled plants upon their retirements as coal-fueled facilities in 2027 and 2028, respectively.

•Uprated capacity at existing plants — In January 2026, we announced plans to add 433 MW of uprate capacity from our Perry, Davis-Besse, and Beaver Valley nuclear power plants in PJM. Additional capacity has been added to existing natural gas plants through technological upgrades improving efficiency and overall fleet intensity.

•Battery Energy Storage Projects — As of December 31, 2025, we owned battery ESS totaling 350 MW in California, 270 MW in Texas and 4 MW in Illinois. We have announced our plans to develop additional battery ESS in California and at retired or to-be-retired plant sites in Illinois.

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•Solar Projects — As of December 31, 2025, we owned solar generations facilities totaling 538 MW in Texas and 112 MW in Illinois. We have announced our plans to develop additional solar generation facilities in California and at retired or to-be retired plant sites in Illinois with expected commercial operation dates beginning in 2026.

We will only invest in growth projects if we are confident in the expected returns.

Greenhouse Gas Emissions (GHG)

In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing. Units permanently retiring by January 1, 2032 are exempt from the rule. Given our previously announced coal unit retirement commitments, our Martin Lake and Oak Grove plants are the only coal units that are subject to this rule. Our Graham, Lake Hubbard, Stryker Creek and Trinidad oil/natural gas facilities are also regulated under this rule. None of our existing large or small combustion turbines are subject to this rule. Following finalization of the rule in May 2024, 17 petitions for review from various states, industry groups, and companies were filed in the D.C. Circuit Court along with multiple motions to stay the rule. We are participating in an industry coalition challenging the rule. Oral argument on the merits of the legal challenges to the rule was held in December 2024 before the D.C. Circuit Court. The D.C. Circuit Court has granted the EPA's motion for an abeyance of the case and status reports are due at 90-day intervals. In June 2025, the EPA published a proposed repeal of GHG emission standards for fossil fuel-fired electric generation units, which could moot this case if the proposal is finalized and would result in no further federal regulation of GHGs at electric generating units. Additionally, in February 2026, the EPA issued a rule that repeals the agency's prior 2009 endangerment finding for all GHG emission standards for light-, medium-, and heavy-duty vehicles. The rescission of the endangerment finding does not impact power plants, however, the EPA has also stated that, for other rules that have relied on the endangerment finding, it intends to initiate other rulemakings to address any overlapping issues. Several environmental groups have filed a challenge to the EPA's repeal of the endangerment finding in the D.C. Circuit Court.

State Regulation of GHGs

Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change.

Regional Greenhouse Gas Initiative (RGGI) — RGGI is a state-driven GHG emission control program that took effect in 2009 and was initially implemented by ten New England and Mid-Atlantic states to reduce CO2 emissions from power plants. The participating RGGI states implemented a cap-and-trade program. Compliance with RGGI can be achieved by reducing emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. We are required to hold allowances equal to at least 50 percent of emissions in each of the first two years of the three-year control period.

In July 2025, the RGGI states completed their third program review and enacted changes to take effect in 2027-2037. Key changes include a tightened regional CO2 annual cap with a 10.5% annual cap starting in 2027 through 2033, followed by a 3% reduction from 2034 to 2037, elimination of offsets, and higher, two-tiered costs containment reserves to manage price volatility.

Our generation facilities in Connecticut, Delaware, Maine, Massachusetts, New Jersey, New York and Rhode Island emitted approximately 16 million short tons of CO2 during 2025. The spot market price of RGGI allowances required to operate these facilities as of December 31, 2025 was approximately $25.86 per allowance. While the cost of allowances required to operate our RGGI-affected facilities is expected to increase in future years, we expect that the cost of compliance would be reflected in the power market, and the actual impact to gross margin would be largely offset by an increase in revenue.

Massachusetts — In August 2017, the Massachusetts Department of Environmental Protection (MassDEP) adopted final rules establishing an annual declining limit on aggregate CO2 emissions from 21 in-state fossil-fueled electricity generation units. The rules establish an allowance trading system under which the annual aggregate electricity generation unit sector cap on CO2 emissions declines from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. MassDEP allocated emission allowances to affected facilities for 2018. Beginning in 2019, the allocation process transitioned to a competitive auction process whereby allowances are partially distributed through a competitive auction process and partially distributed based on the process and schedule established by the rule. Beginning in 2021, all allowances were distributed through the auction. Limited banking of unused allowances is allowed.

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Virginia — In May 2019, the Virginia Department of Environmental Quality issued a final rule to adopt a carbon cap-and trade program for fossil-fueled electricity generation units, including our Hopewell facility, beginning in 2020. The program is based on the RGGI proposed 2017 model rule and linked Virginia to RGGI in 2021. The former Governor of Virginia issued an executive order in January 2022 to begin the process of removing the state from RGGI. The Virginia State Pollution Control Board withdrew the state from RGGI at the end of 2023, coinciding with the end of the program's three-year compliance period and contract with RGGI, Inc. In August 2023, opponents of the state's action filed suit seeking a stay alleging withdrawal from RGGI is impermissible without new legislation. In November 2024, a state circuit court judge ruled that the removal of Virginia from RGGI was unlawful, but the state has moved to stay the circuit court's judgment. Virginia is not participating in RGGI at this time. In February 2026, following the 2025 election, legislation was introduced to have Virginia join RGGI. If this legislation becomes law, Virginia could join RGGI as early as the second half of 2026.

New Jersey — In January 2018, the Governor of New Jersey signed an executive order directing the state's environmental agency and public utilities board to begin the process of rejoining RGGI, and New Jersey formally rejoined RGGI in June 2019. In June 2019, New Jersey adopted two rules that govern New Jersey's reentry into the RGGI auction and distribution of the RGGI auction proceeds.

Pennsylvania — In April 2022, the Pennsylvania Environmental Quality Board finalized regulations that would establish Pennsylvania's participation in RGGI. However, in November 2025, legislation was enacted that removed Pennsylvania from RGGI. As a result, RGGI is not being implemented in Pennsylvania.

California — Our assets in California are subject to the California Global Warming Solutions Act, which required the California Air Resources Board (CARB) to develop a GHG emission control program to reduce emissions of GHGs in the state to 1990 levels by 2020. In April 2015, the Governor of California issued an executive order establishing a new statewide GHG reduction target of 40 percent below 1990 levels by 2030 to ensure California meets its 2050 GHG reduction target of 80 percent below 1990 levels. We have participated in quarterly auctions or in secondary markets, as appropriate, to secure allowances for our affected assets.

In July 2017, California enacted legislation extending its GHG cap-and-trade program through 2030 and the CARB adopted amendments to its cap-and-trade regulations that, among other things, established a framework for extending the program beyond 2020 and linking the program to the new cap-and-trade program in Ontario, Canada beginning in January 2018.

Air Emissions

The Clean Air Act (CAA)

The CAA and comparable state laws and regulations relating to air emissions impose various responsibilities on owners and operators of sources of air emissions, which include requirements to obtain construction and operating permits, pay permit fees, monitor emissions, submit reports and compliance certifications, and keep records. The CAA requires that fossil-fueled electricity generation plants meet certain pollutant emission standards and have sufficient emission allowances to cover SO2 emissions and in some regions NOX emissions.

In order to ensure continued compliance with the CAA and related rules and regulations, we utilize various emission reduction technologies. These technologies include flue gas desulfurization (FGD) systems, dry sorbent injection (DSI), baghouses and activated carbon injection or mercury oxidation systems on select units and electrostatic precipitators, selective catalytic reduction (SCR) systems, low-NOX burners and/or overfire air systems on all units.

Cross-State Air Pollution Rule (CSAPR) and Good Neighbor Plan

In 2016, the EPA finalized the Cross-State Air Pollution Rule Update (CSAPR Update) to address 22 states' obligations with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). In 2019, following challenges by numerous parties, the D.C. Circuit Court found that the CSAPR Update did not fully address certain states' 2008 ozone NAAQS obligations. In October 2020, the EPA proposed an action to address the outstanding 2008 ozone NAAQS obligations in response to the D.C. Circuit Court's 2019 ruling. The EPA published a final rule in the Federal Register on April 30, 2021 that reduces ozone season NOX budgets in certain states. We do not believe that the final rule causes a material adverse impact on our future financial results.

VISTRA CORP.

In October 2015, the EPA revised the primary and secondary ozone NAAQS to lower the eight-hour standard for ozone emissions during ozone season (May to September), and, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA, which was then disapproved by the EPA in February 2023. The State of Texas, Luminant, certain trade groups, and others challenged that disapproval in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). In March 2025, the Fifth Circuit Court denied those petitions for review, but we and the State of Texas have filed petitions for rehearing of that decision. We do not expect any near-term impact to Texas sources from this decision. Based on policy recent pronouncements from the Trump administration, the new EPA is reevaluating its approach to these Good Neighbor SIPs in general.

In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS. In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP). The FIP applied to 22 states beginning with the 2023 ozone seasons. States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia, and West Virginia.

In June 2024, the U.S. Supreme Court granted a stay of the GNP FIP pending a review of the merits by the D.C. Circuit Court and any further appeal to the U.S. Supreme Court. As a result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP. In April 2025, the D.C. Circuit Court granted an abeyance of the case challenging the GNP FIP addressing interstate transport for all covered states while the EPA reviews the GNP FIP. In January 2026, the EPA proposed removing eight states (although none that we operate in) from the GNP FIP, and we expect the EPA will take additional action to reconsider other aspects of the GNP FIP in 2026. At this time, we do not know how these proposed changes could impact the overall trading program for any states that remain in the GNP FIP.

Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas

The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory class I federal areas which impairment results from man-made pollution". There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second, certain electricity generation units built between 1962 and 1977 are subject to BART standards designed to improve visibility if such units cause or contribute to impairment of visibility in a federal class I area.

In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 SIP and a partial FIP. For SO2, the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019. In May 2023, a proposed BART rule was published in the Federal Register that would withdraw the trading program provisions of the prior rule and would establish SO2 limits on six facilities in Texas, including Martin Lake and Coleto Creek. However, that proposal was never finalized during the Biden administration. In December 2025, the EPA issued a final rule for reasonable progress requirements that (a) approves portions of Texas' first planning period regional haze SIP and (b) approves Texas' second planning period regional haze SIP. Under the EPA's rule, no new controls are required.

National Ambient Air Quality Standards (NAAQS)

The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment. The EPA has established NAAQS for six such pollutants, including SO2 and ozone. Each state is responsible for developing a SIP that will attain and maintain the NAAQS. These plans may result in the imposition of emission limits on our facilities.

VISTRA CORP.

SO2 Designations for Texas

In November 2016, the EPA finalized nonattainment designations for SO2 for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations required Texas to develop nonattainment plans for these areas. In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO2 emissions from the plant. The proposed agreed order associated with the SIP proposal reduced emission limits as of January 2022. Emission reductions required are those necessary to demonstrate attainment with the NAAQS. In February 2022, we and the TCEQ entered into an agreed order to reduce SO2 emissions at the Martin Lake plant, and the TCEQ submitted the agreed order to the EPA as a SIP revision to address the nonattainment designation. We and the State of Texas had previously filed legal challenges in 2017 to the EPA's nonattainment designations in the Fifth Circuit Court. In May 2025, the Fifth Circuit Court held that the EPA's designations were unlawful, granted the petitions for review, and remanded the designation back to the EPA. In September 2025, the EPA issued a final rule withdrawing its Finding of Failure to Submit and Finding of Failure to Attain in light of the Fifth Circuit Court's May 2025 decision.

Ozone Designations

The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. Areas surrounding our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet facility in Illinois and our Wise, Ennis and Midlothian facilities in Texas were designated marginal nonattainment areas in June 2018 by the EPA with an attainment deadline of August 2021. In June 2022, the areas surrounding our Ohio Dicks Creek and Miami Fort facilities were redesignated "attainment." The EPA redesignated the area around our Texas Wise, Ennis and Midlothian facilities to "moderate" in October 2022 and again "bumped up" the classification to serious in June 2024. Middlesex County in New Jersey, where our Sayreville facility is located, was designated a "moderate" nonattainment area. In July 2024, the state of New Jersey, in collaboration with the states of New York and Connecticut requested a voluntary bump up of the New York-Northern New Jersey-Long Island nonattainment area, which includes Middlesex County where our Sayreville facility is located. States will be required to develop SIPs to address emissions in areas with a higher (more stringent) classification.

Coal Combustion Residuals (CCR)/Groundwater

The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at power generation facilities in dry form in landfills and in wet form in surface impoundments. Each of our coal-fueled plants has at least one CCR surface impoundment.

CCR Rule Revisions and Extension Applications

The EPA's CCR rule, which took effect in October 2015, establishes minimum federal requirements for the construction, retrofitting, operation and closure of, and corrective action with respect to, existing and new CCR landfills and surface impoundments, as well as inactive CCR surface impoundments. The requirements include location restrictions, structural integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping and notification. The deadlines for beginning and completing closure vary depending on several factors. The Water Infrastructure Improvements for the Nation Act (the WIIN Act), which was enacted in December 2016, provides for EPA review and approval of state CCR permit programs.

In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a final rule establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The 2020 final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue).

Prior to the November 2020 deadline to seek extensions, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications.

VISTRA CORP.

Legacy CCR Rulemaking

In May 2024, the EPA published a final rule that expands coverage of groundwater monitoring and closure requirements to the following two new categories of units: (a) legacy CCR surface impoundments which are CCR surface impoundments that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015 and (b) "CCR management units" (CCRMUs) which generally could encompass noncontainerized ash deposits greater than one ton and impoundments and landfills that closed prior to October 19, 2015. As part of the rule, the EPA identified numerous CCR management units across the country, including ten of our potential units. The Vermilion ash ponds discussed below are the only unit which we believe qualify as a legacy CCR surface impoundment and given our closure plan for that site we do not believe the rule will have any impact on that site. CCRMUs with 1,000 or more tons of CCR must comply with the CCR's groundwater monitoring, corrective action, closure and post-closure requirements. For CCRMUs, complete facility evaluation reports are due within 33 months after publication of the rule, initial groundwater reports are due January 31, 2029, and the deadline to initiate closure, if needed, will start in 2029. Closure of the CCRMUs may also be deferred beyond those dates depending on certain factors, including where the CCRMU is located beneath critical infrastructure. In addition, certain closures may not be required when closure was previously approved under a state program. Because facility evaluation reports will determine our unit-specific compliance obligations, we cannot determine them at this time. In August 2024, we, along with USWAG, several other generating companies, and 17 states, including Texas, filed a challenge to the rule in the D.C. Circuit Court. In February 2025, the D.C. Circuit Court granted an unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. In February 2026, the EPA issued a final rule for the CCRMU provisions of the rule extending the deadlines for the Facility Evaluation Reports (FER) to 2028, groundwater monitoring to 2031, and closure requirements to 2030. The EPA has requested to keep the challenge to the rule addressing CCRMUs and legacy impoundments in abeyance.

MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility.

At our retired Vermilion facility, in June 2021, we entered into an agreed interim consent order with the Illinois Attorney General and the Vermilion County State Attorney in which DMG is required to evaluate the closure alternatives under the requirements of the Illinois Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash. These proposed closure costs are reflected in the ARO in the consolidated balance sheets (see Note 15 to the Financial Statements for additional information).

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule.

In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of guidelines, rules, and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal at any site. In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in January 2022 and five of our sites in July 2022. One additional closure construction application was filed for our Baldwin facility in August 2023. In 2025, we filed construction permit applications (or supplemented prior operating permit applications) to cover corrective action activities at 11 impoundments across our Illinois fleet.

VISTRA CORP.

For all of the above CCR matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not require removal. However, the rule required us to undertake further site-specific evaluations required by each program. We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been approved by the IEPA and as such, an estimate of such costs cannot be made. The CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the costs of closure methods that our operations and environmental services teams determined were appropriate based on the existing closure requirements at the time we recorded those ARO liabilities, and it is reasonably possible for those to increase once the IEPA determines final closure requirements. Once the IEPA acts on our permit applications, we will reassess the decommissioning costs and adjust our ARO liabilities accordingly.

Water

The EPA and the environmental regulatory bodies of states in which we operate have jurisdiction over the diversion, impoundment and withdrawal of water for cooling and other purposes and the discharge of wastewater (including storm water) from our facilities. We believe our facilities are presently in material compliance with applicable federal and state requirements relating to these activities. We believe we hold all required permits relating to these activities for facilities in operation and have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals.

Effluent Limitation Guidelines (ELGs) — In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as FGD, fly ash, bottom ash, and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. In October 2020, the EPA published a final rule that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Notifications were made to Texas, Illinois, and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. In May 2024, the EPA published the final ELG rule revisions, which contain new requirements for legacy wastewater and combustion residual leachate. The final rule also leaves in place the subcategory for facilities that permanently cease coal combustion by 2028. A number of parties have since challenged the rule and that case is pending in the U.S. Court of Appeals for the Eighth Circuit. We are not a party to that litigation. In February 2025, the U.S. Court of Appeals for the Eighth Circuit granted the EPA's unopposed motion seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

In December 2025, the EPA finalized additional revisions to the ELG rule, including extending certain compliance deadlines under the 2024 ELG rule. Those deadlines would generally apply to facilities that had not already utilized the retirement provisions in the 2020 ELG rule, which our company had utilized. In addition, the rule authorizes a process for states to extend the 2028 retirement deadline that was finalized as part of the 2020 ELG rule in the event market conditions would not support retirement of a facility. We are currently evaluating this rule and the impact, if any, it might have on our announced plans to retire our remaining coal generation facilities in Illinois and Ohio by 2028 given that those facilities are under separate existing regulatory requirements to close by then. Several environmental groups have recently challenged that rule.

Radioactive Waste

The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily using dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the U.S. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear fuel storage capability is sufficient for the foreseeable future.

VISTRA CORP.

Corporate Information

Vistra is a Delaware corporation whose common stock is listed and traded on the NYSE and the NYSE Texas. Our principal executive office is located at 6555 Sierra Drive, Irving, Texas 75039. The telephone number for our principal executive office is (214) 812-4600. We maintain a website located at www.vistracorp.com.

Available Information

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports with the SEC. You may obtain copies of these documents, free of charge, on the SEC's website at www.sec.gov or on Vistra's website at www.vistracorp.com, as soon as reasonably practicable after they have been filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. Vistra also posts important information, including press releases, investor presentations, sustainability reports, and notices of upcoming events on its website and utilizes its website as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of postings to our website by signing up for email alerts and RSS feeds on the "Investor Relations" page. The information on Vistra's website shall not be deemed a part of, or incorporated by reference into, this annual report on Form 10-K.

VISTRA CORP.

Item 1A.RISK FACTORS

Summary of Risk Factors

The following summarizes the principal factors that make an investment in our company speculative or risky, all of which are more fully described in the Risk Factors section below. This summary should be read in conjunction with the Risk Factors section and should not be relied upon as an exhaustive summary of the material risks facing our business. The following factors could result in harm to our business, financial condition, results of operations, cash flows, and prospects, among other impacts:

Market, Financial, and Economic Risks

•Our revenues, results of operations, and operating cash flows are affected by price fluctuations in the wholesale power market and other market factors beyond our control.

•We purchase natural gas, coal, fuel oil, and nuclear fuel for our generation facilities, and higher than expected fuel costs or disruptions in these fuel markets may have an adverse impact on, our costs, revenues, results of operations, financial condition, and cash flows.

•We have retired, announced planned retirements of, and may be forced to retire or idle additional underperforming generation units which could result in significant costs and have an adverse effect on our operating results.

•Our assets or positions cannot be fully hedged against changes in commodity prices and Market Heat Rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.

•If electricity demand does not grow at the rate expected, or if we are unable to execute on large load offtake opportunities, including under long-term power purchase or offtake agreements that we have entered into, our financial performance, growth opportunities, and stock price could be adversely impacted.

•Competition, changes in market structure, and/or state or federal interference in the wholesale and retail power markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations, and cash flows.

•Our results of operations and financial condition could be materially and adversely affected by energy market participants continuing to construct new generation facilities or expanding or enhancing existing generation facilities despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices.

•Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in the future, which could have a material adverse effect on us.

•The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions and limitations that could affect our ability to operate our business, our liquidity, and our results of operations, and any failure to comply with these restrictions could have a material adverse effect on us.

•We may not be able to consummate the Cogentrix Transactions on the anticipated terms, on the anticipated timeline, or at all, which could adversely affect our business, financial condition, results of operation and stock price.

•Following completion of the Cogentrix Transactions, we may not realize the anticipated synergies and other expected benefits of the Cogentrix Transactions on the anticipated timeline or at all.

•We may not be able to complete future acquisitions on favorable terms or at all, successfully integrate future acquisitions into our business, or effectively identify and invest in value-creating businesses, assets or projects, which could result in unanticipated expenses and losses or otherwise hinder or delay our growth strategy.

•Our ability to achieve the expected growth of our Vistra Zero portfolio, consisting of our solar generation, battery ESS, and other renewables development projects, is subject to substantial capital requirements and other significant uncertainties.

•Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or increased taxes or fees, could have a material adverse effect on our financial condition, results of operations, and cash flows.

VISTRA CORP.

Regulatory and Legislative Risks

•Our businesses are subject to ongoing complex governmental regulations and legislation that have adversely impacted, and may in the future adversely impact, our businesses, results of operations, liquidity and financial condition.

•Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.

•Pending or proposed laws or regulations, or the repeal of existing beneficial laws or regulations, including those proposed or implemented under the Trump administration, could have a material adverse effect on our businesses, results of operations, liquidity and financial condition.

•Changes to laws, rules or regulations related to market structures in the markets in which we participate may have a material adverse effect on our businesses, results of operation, liquidity and financial condition.

•We could be materially and adversely affected if current regulations are implemented or if new federal or state legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.

•Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us.

Operational Risks

•Volatile power supply costs and demand for power have and could in the future adversely affect the financial performance of our retail businesses.

•Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing customers and the inability to attract new customers.

•Cybersecurity attacks or technology systems failures could disrupt business operations and expose us to significant liabilities, reputational damage, loss of customers, and regulatory action.

•The operation of our businesses is subject to information security and operational technology risks, including cybersecurity breaches and failure of critical information and operations technology systems. Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could have a material adverse effect on us.

•We may suffer material losses, costs and liabilities due to operational risks, regulatory risks, and the risk of nuclear accidents arising from the ownership and operation of the nuclear generation facilities.

•The operation and maintenance of power generation facilities and related mining operations are capital intensive and involve significant risks that could adversely affect our results of operations, liquidity and financial condition.

•We may be materially and adversely affected by obligations to comply with federal and state regulations, laws, and other legal requirements that govern the operations, assessments, storage, closure, corrective action, disposal and monitoring relating to CCR.

•We have been and may in the future be materially and adversely affected by the effects of extreme weather conditions and seasonality.

•Events outside of our control, including an epidemic or outbreak of an infectious disease may materially adversely affect our business.

•Changes in technology, increased electricity conservation efforts, or energy sustainability efforts may reduce the value of our business, introduce new or emerging risks and may otherwise have a material adverse effect on us.

Risks Related to Our Structure and Ownership of our Common Stock

•Evolving expectations from stakeholders, including investors, on sustainability issues, including climate risk, and erosion of stakeholder trust or confidence could influence actions or decisions about our company and our industry and could adversely affect our business, operations, financial results, or stock price.

•We may not pay any dividends on our common stock in the future, and we may not realize the anticipated benefits of our share repurchase program.

VISTRA CORP.

Please carefully consider the following discussion of significant factors, events, and uncertainties that make an investment in our securities risky. These factors, in addition to others specifically addressed in Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations (MD&A), provide important information for the understanding of our forward-looking statements in this annual report on Form 10-K. If one or more of the factors, events and uncertainties discussed below or in the MD&A were to materialize, our business, results of operations, liquidity, financial condition, cash flows, reputation or prospects could be materially adversely affected. In addition, if one or more of such factors, events and uncertainties were to materialize, it could cause results or outcomes to differ materially from those contained in or implied by any forward-looking statement in this annual report on Form 10-K. There may be further risks and uncertainties that are not currently known or that are not currently believed to be material that may adversely affect our business, results of operations, liquidity, financial condition and prospects and the market price of our common stock in the future. The realization of any of these factors could cause investors in our securities (including our common stock) to lose all or a substantial portion of their investment.

Market, Financial and Economic Risks

Our revenues, results of operations and operating cash flows generally are affected by price fluctuations in the wholesale power market and other market factors beyond our control.

We are not guaranteed any rate of return on capital investments in our businesses. We conduct integrated power generation and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales of electricity and natural gas to end users and commodity risk management. Our wholesale and retail businesses are to some extent countercyclical in nature, particularly for the wholesale power and ancillary services supplied to the retail business. However, we do have a wholesale power position that is subject to wholesale power price moves, which may be significant. As a result, our revenues, results of operations and operating cash flows depend in large part upon wholesale market prices for electricity, natural gas, uranium, lignite, coal, fuel oil, and transportation in our regional markets and other competitive markets in which we operate and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of regulatory authorities.

Market prices for power, capacity, ancillary services, natural gas, coal and fuel oil are unpredictable and may fluctuate substantially over relatively short periods of time. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. Over-supply can occur as a result of the construction of new power generation sources. During periods of over-supply, electricity prices might be depressed. For example, in many instances, energy from renewable resources, such as solar, wind and battery ESS, are bid into the relevant spot market at a price of zero or close to zero during certain times of the day, lowering the clearing price for all power wholesalers in such market. Also, at times there is political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.

Extreme weather events can also materially impact power prices or otherwise exacerbate conditions or circumstances that result in volatility of power prices. For example, severe winter storms across the U.S. such as Winter Storm Uri in February 2021 and Winter Storm Fern in January 2026, and extreme cold temperatures in the central U.S., including Texas, resulted in widespread wholesale power market volatility, substantial increases in the costs to procure sufficient fuel supply, and increased collateral posting requirements.

The majority of our facilities operate as "merchant" facilities without long-term power sales agreements. As a result, we largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other wholesale and retail power markets on a short-term basis and are not guaranteed any rate of return on our capital investments. Consequently, we may not be able to sell any or all of the electric energy, capacity or ancillary services from those facilities at commercially attractive rates or that our facilities will be able to operate profitably. We depend, in large part, upon prevailing market prices for power, capacity and fuel. Given the volatility of commodity power prices, to the extent we are unable to hedge or otherwise secure long-term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to volatility, and our financial condition, results of operations and cash flows could be materially adversely affected.

VISTRA CORP.

We purchase natural gas, coal, fuel oil, and nuclear fuel for our generation facilities, and higher than expected fuel costs, volatility, or disruption in these fuel markets may have an adverse impact on our costs, revenues, results of operations, financial condition and cash flows.

We rely on natural gas, coal, fuel oil, and nuclear fuel for the majority of our power generation facilities. Delivery of these fuels to the facilities is dependent upon the continuing availability of such fuels and financial viability of contractual counterparties as well as upon the infrastructure (including mines, rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available and functioning to serve each generation facility, and geopolitical risk, including the current Russia and Ukraine conflict and the potential for additional U.S. sanctions against Russia or other potential restrictions on Russian energy deliveries. See Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations – Business Environment and Outlook. As a result, we have experienced, and remain subject to the risks of disruptions or curtailments in the production of power at our generation facilities if no fuel is available at any price, if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure. Certain of our generation facilities rely on a limited number of counterparties, such as natural gas suppliers and railcar companies, to provide the necessary fuel. Disputes relating to or non-performance of contractual arrangements have resulted in, and may continue to result in adverse impacts to our costs, revenues, results of operations, financial condition, and cash flows.

As part of our strategy to mitigate the potential negative effects of commodity price volatility, we have sold forward a substantial portion of our expected power sales in the next few years in order to lock in long-term prices. In order to hedge our obligations under these forward power sales contracts, we have entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Fuel costs (including diesel, natural gas, lignite, coal and nuclear fuel) are volatile, and the wholesale price for power does not always change at the same rate as changes in fuel costs, and disruptions in our fuel supplies may therefore require us to find alternative fuel sources at costs which may be higher than planned, to find other sources of power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Long-term and short-term contracts are subject to risk of non-delivery or claims of force majeure, which may impact our ability to economically recover the value of the contract. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting our obligations. Further, any changes in the costs of natural gas, coal, fuel oil, nuclear fuel or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we consider favorable, or if we are unable to procure these fuels at all, our financial condition, results of operations and cash flows could be materially adversely affected. For example, supply challenges were among the primary drivers of the significant loss experienced in 2021 as a result of Winter Storm Uri.

We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. The mismatch between the gas day and related nomination cycles and the power day and ISO/RTO market timing may result in fuel procurement challenges. This may have a material adverse effect on our financial and operating performance. Volatility in market prices for fuel and power results from, among other factors:

•demand for energy commodities and general economic conditions, including impacts of inflation and the relative strength or weakness of U.S. dollar compared to other currencies;

•volatility in commodity prices and the supply of commodities, including but not limited to natural gas, coal and fuel oil;

•volatility in Market Heat Rates;

•volatility in coal and rail transportation prices;

•volatility in nuclear fuel and related enrichment and conversion services;

•transmission or transportation disruptions, constraints, congestion, inoperability or inefficiencies of electricity, natural gas or coal transmission or transportation, or other changes in power transmission infrastructure;

•severe, sustained or unexpected weather conditions, including extreme cold, drought and limitations on access to water;

•seasonality;

•changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors;

•illiquidity in the wholesale power or other commodity markets;

•importation of liquified natural gas to certain markets;

•development and availability of new fuels, new technologies and new forms of competition for the production and storage of power, including competitively priced alternative energy sources or storage;

VISTRA CORP.

•changes in market structure and liquidity;

•changes in the way we operate our facilities, including curtailed operation due to market pricing, environmental regulations and legislation, safety or other factors;

•changes in generation capacity or efficiency;

•outages or otherwise reduced output from our generation facilities or those of our competitors;

•changes in electric capacity, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to federal, state or local subsidies, or additional transmission capacity;

•local, regional, national, or global supply chain constraints or shortages;

•our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;

•changes in the credit risk, payment practices, or financial condition of market participants;

•changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products;

•pandemics and epidemics (including the impacts thereto, or recovery therefrom), natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events; and

•changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and legislation.

See "Economic downturns would likely have a material adverse effect on our businesses" for a discussion of potential risks arising from current U.S. and global economic and geopolitical conditions.

We have retired, announced planned retirements of, and may be forced to retire or idle additional underperforming generation units which could result in significant costs and have an adverse effect on our operating results.

A sustained decrease in the financial results from, or the value of, our generation units has resulted in the retirement or planned retirement of, and ultimately could result in additional retirements or idling of, generation units. We have operated certain of our lignite- and coal-fueled generation assets only during parts of the year that have higher electricity demand and, therefore, higher related wholesale electricity prices. In connection with the closure and remediation of retired generation units, we have spent, and may in the future spend, a significant amount of money, internal resources and time to complete the required closure and reclamation, which could have a material adverse effect on our financial and operating performance.

Our assets or positions cannot be fully hedged against changes in commodity prices and Market Heat Rates, and hedging transactions may not work as planned, or counterparties may default on their obligations, which could have a material adverse impact on our business, financial condition, results of operations and cash flows.

Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notably electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative to the duration of available markets for various hedging activities. Generally, commodity markets that we participate in to hedge our exposure to electricity prices and Market Heat Rates have limited liquidity after two to three years. Further, our ability to hedge our revenues by utilizing cross-commodity hedging strategies with natural gas hedging instruments is generally limited to a duration of four to five years. To the extent we have unhedged positions, fluctuating commodity prices and/or Market Heat Rates can materially impact our results of operations, cash flows, liquidity and financial condition, either favorably or unfavorably.

VISTRA CORP.

To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, diesel fuel, uranium and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Given our exposure to risks of commodity price movements, we devote a considerable amount of time and effort to the establishment of risk management policies and procedures, as well as the ongoing review of the implementation of these policies and procedures. Additionally, we have processes and controls in place that are designed to monitor and accurately report hedging activities and positions. The policies, procedures, processes and controls in place may not always function as planned and cannot eliminate all the risks associated with these activities, including unauthorized hedging activity, or improper reporting thereof, by our employees in violation of our existing risk management policies and procedures. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, consumer behavior, market constraints or other factors could cause us to purchase electricity to meet unexpected demand in periods of high wholesale market prices or resell excess electricity into the wholesale market in periods of low prices. As a result of these and other factors, the impacts of our commodity hedging activities and risk management decisions may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Based on economic and other considerations, including our available liquidity, we may not be able to, or we may decide not to, hedge the entire exposure of our operations to commodity price risk. To the extent we do not hedge against commodity price risk and applicable commodity prices change in ways adverse to us, we could be materially and adversely affected. To the extent we do hedge against commodity price risk, those hedges may ultimately prove to be ineffective. Additionally, there may be changes to existing laws or regulations that could significantly impact our ability to effectively hedge, which may have a material adverse effect on us.

To the extent we engage in hedging and risk management, and power purchase agreement activities, we are exposed to the credit risk that counterparties that owe us money, energy or other commodities as a result of these activities will not perform their obligations to us. Should the counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. Additionally, our counterparties may seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount due to us. Any such losses or impairments to the carrying value of our financial assets could materially and adversely affect our financial condition, results of operations and cash flows. In such event, we could incur losses or forgo expected gains in addition to amounts, if any, already paid to the counterparties. Market participants in the ISOs/RTOs in which we operate are also exposed to risks that another market participant may default on its obligations to pay such ISO/RTO for electricity or services taken, in which case such costs, to the extent not offset by posted security and other protections available to such ISO/RTO, may be allocated to various non-defaulting ISO/RTO market participants, including us.

We do not apply hedge accounting to our commodity derivative transactions, which may cause increased volatility in our quarterly and annual financial results.

We enter derivative instruments to manage commodity price risks. All our derivatives are accounted for as economic hedges and are recorded at estimated fair value in the consolidated balance sheets with changes in fair value recorded as gains or losses in the earnings of the period in which they occur. No derivative positions are accounted for as cash flow or fair value hedges.

A derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. While certain retail sales contract portfolios are designated as normal, the majority of our derivative positions are subject to adjustments caused by changes in forward commodity prices. As a result, our quarterly and annual financial results, prepared in accordance with GAAP, are subject to increased volatility.

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If electricity demand does not grow at the rate expected, or if we are unable to execute on large load offtake opportunities, including under long-term power purchase or offtake agreements that we have entered into, our financial performance, growth opportunities, and stock price could be adversely impacted.

Multiple demand drivers such as emergence of large load data centers, including in response to transformations in technologies like artificial intelligence (AI) and electrification of oil field operations (specifically in the Permian Basin of west Texas), have accelerated, and are expected to continue to accelerate, load growth in the geographic regions we serve. We continue to pursue and execute on additional opportunities for the prospective sale of power from our generation fleet facilities pursuant to long-term agreements to supply large load facilities. The successful execution of such agreements may depend on our ability to complete related projects, enhancements, uprates or operational improvements within specified timelines, budgets and performance parameters.

Such transactions and executed agreements are subject to certain risks and uncertainties, including various currently contemplated or future potential regulatory actions, reviews, and/or approvals, adverse legislative actions, and project execution risk including significant capital expenditures required to complete the nuclear uprates, as well as risks related to operational performance, fuel supply and other factors, that could affect our ability to meet contractual obligations, which could impact the timing of, and our ability to consummate, such transactions. In addition, if demand does not continue to increase at a rate in line with market expectations due to various factors, such as changes in technology, more energy efficient AI solutions or slow adoption of AI products and services, economic downturns, or adverse government actions, or if we are unable to execute on such large load offtake opportunities and perform our obligations under executed agreements as anticipated, our opportunities for growth and stock price may be adversely impacted.

Competition, changes in market structure, and/or state or federal interference in the wholesale and retail power markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale marketplace may be undermined by changes in market structure and out-of-market subsidies provided by federal or state entities, including bailouts of uneconomic plants, imports of power from Canada, renewable mandates or subsidies, as well as out-of-market payments to new generators. Multiple potential changes have been and are being evaluated by the PUCT and the Texas Legislature for the ERCOT market, including Dispatchable Reliability Reserve Service that would facilitate compliance with a required reliability standard, the ultimate resolution of which is unknown. Similarly, the Administration's use of Executive Orders and engagement by the PJM Governors could add regulatory uncertainty to the extent resource entry and exit decisions become disconnected from market fundamentals. In another example, the resolution of a number of filings pending at FERC could impact PJM capacity market rules in future years.

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generation facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable generation increases competition from these types of facilities and out-of-market subsidies to existing or new generation can undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by us.

We also compete against other energy merchants on the basis of our relative operating skills, financial position and access to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources or experience in these areas. Over time, some of our plants may become unable to compete because of subsidized generation, including public utility commission supported power purchase agreements, and the construction of new plants. Such new plants could have a number of advantages including more efficient equipment and newer technology that could result in fewer emissions or more advantageous locations on the electric transmission system. Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived from owning more efficient facilities.

VISTRA CORP.

Other factors may contribute to increased competition in wholesale power markets. We expect that we will continue to face intense competition from numerous companies, including new entrants or consolidation of existing competitors, in the industry. Certain federal and state entities in jurisdictions in which we operate have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic plants and attempt to incentivize, including through certain tax benefits, the construction and development of additional renewable resources as well as increases in energy efficiency investments.

In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins that we can earn on the volumes we are able to serve. Further, with retail competition, it is easier for residential customers where we serve load to switch competitive electricity generation suppliers for their energy needs. The volatility and uncertainty that results from such mobility may have material adverse effects on our financial condition, results of operations and cash flows. For example, if fewer customers switch to another supplier than anticipated, the load we must serve will be greater than anticipated, and if market prices of fuel have increased, our costs will increase more than expected due to the need to go to the market to cover the incremental supply obligation. If more customers switch to another supplier than anticipated, the load we must serve will be lower than anticipated and, if market prices of electricity have decreased, our operating results could suffer.

Our results of operations and financial condition could be materially and adversely affected by energy market participants continuing to construct new generation facilities or expanding or enhancing existing generation facilities despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices.

Given the overall attractiveness of certain markets in which we operate, continued customer interest in zero carbon resources, and certain tax benefits associated with renewable energy, among other matters, energy market participants have continued to construct new generation facilities or invest in enhancements or expansions of existing generation facilities despite relatively low wholesale power prices. Assuming this market dynamic continues, our results of operations and financial condition could be materially and adversely affected if such additional generation capacity results in an over-supply of electricity that causes a reduction in wholesale power prices. Additionally, new or existing market participants without, or with less, fossil fuel operations may gain additional market share, or reduce our market share, due to evolving expectations and sentiments of key stakeholders, government, and regulatory authorities regarding our operations and activities.

Economic downturns would likely have a material adverse effect on our businesses.

Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including lower prices for power and natural gas, which can fluctuate substantially, and lower generation output. Increased unemployment of residential customers and decreased demand for products and services by commercial and industrial customers resulting from an economic downturn could lead to declines in the demand for energy and an increase in the number of uncollectible customer balances, which would negatively impact our overall sales and cash flows. The convergence of current global conditions, including sustained inflation, elevated interest rates, and the geopolitical climate, has and could lead to, or accelerate or exacerbate the occurrence of, a significant economic downturn, as well as changes in consumer and counterparty behavior, higher costs of capital, decreases in the value of our existing long-dated contracts, commodity price increases and volatility, supply chain shortages, and other adverse impacts to our business. For example, the U.S. administration has taken action or may take action in the future with respect to major changes to trade policies, such as the imposition of tariffs on imported products and the withdrawal from or renegotiation of certain trade agreements. Any such material changes in trade policies, including the imposition of tariffs, could lead to increased supply chain disruptions and increased supply chain costs, which could have a material adverse impact on our business, financial condition and results of operations.

Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in the future, which could have a material adverse effect on us. We currently maintain a mix of investment grade and non-investment grade credit ratings that could negatively affect our ability to access capital on favorable terms or result in higher collateral requirements, particularly if our credit ratings were to be downgraded in the future.

Our businesses are capital intensive. In general, we rely on access to financial markets and credit facilities as a significant source of liquidity for our capital requirements, hedging transactions and other obligations not satisfied by cash-on-hand or operating cash flows. The inability to raise capital or to access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our ability to meet our obligations or sustain and grow our businesses and could increase capital costs and collateral requirements, any of which could have a material adverse effect on us.

VISTRA CORP.

Our access to capital and the cost and other terms of acquiring capital are dependent upon, and could be adversely impacted by, various factors, including:

•general economic and capital markets conditions, including changes in financial markets that reduce available liquidity or the ability to obtain or renew credit facilities on favorable terms or at all;

•conditions and economic weakness in the U.S. power markets;

•regulatory developments;

•changes in interest rates;

•a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results;

•a downgrade of Vistra's or its applicable subsidiaries' credit ratings, or credit ratings of its issuances;

•our level of indebtedness and compliance with covenants in our debt agreements;

•our ability to meet our sustainability targets in our secured credit facilities;

•a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilities that affects the ability of such lender(s) to make loans to us;

•credit, security, or collateral requirements, including those relating to volatility in commodity prices;

•general credit availability from banks or other lenders for us and our industry peers;

•investor and lender confidence in and sentiment of the industry, our business, and the wholesale electricity markets in which we operate;

•a material breakdown in or oversight in effectuating our risk management procedures;

•the occurrence of changes in our businesses;

•disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities and battery ESS; and

•changes in or the operation of provisions of tax and regulatory laws.

There are also financial risks for companies that own and operate fossil fuel generation as some institutional lenders or other sources of capital have become more attentive to sustainable financing practices and some of them may seek commitments on emission reduction targets or expected use or proceeds when providing funding to, or decline to provide funding for companies who produce or utilize fossil fuel energy or that have higher levels of GHG emissions. Our Vistra Operations Credit Agreement contains Sustainability Adjustments. These adjustments use baseline values from KPI Metrics and provide for decreases in the applicable credit spread adjustments and commitment fee rates if our reported metrics are a certain percentage below the baseline values, adjusted on a year-to-year basis. Conversely, if our reported metrics are a certain percentage above the baseline values, adjusted on a year-to-year basis, the applicable credit spread adjustments and fee rates are increased. Building in these adjustments to our credit agreement helps to show lenders we are committed to lowering our GHG emissions, but failing to meet the targets on a regular basis could be viewed negatively by such lenders. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists and others concerned about climate change not to provide funding for companies in the broader energy sector. Limitations on our access to, or increases in our cost of, capital could have a material adverse effect on us.

In addition, we currently maintain a mix of investment grade and non-investment grade credit ratings. As a result, we may not be able to access capital on terms (financial or otherwise) as favorable as companies that maintain full investment-grade credit ratings or we may be unable to access capital at all at times when the credit markets tighten. In addition, due to our credit ratings, counterparties request collateral support (including cash or letters of credit) in order to enter into certain transactions with us.

A downgrade in long-term debt ratings generally causes borrowing costs to increase and the potential pool of investors to shrink and could trigger liquidity demands pursuant to contractual arrangements. Future transactions by Vistra or any of its subsidiaries, including the issuance of additional debt, could result in a temporary or permanent downgrade in our credit ratings.

VISTRA CORP.

Our indebtedness could adversely affect our ability in the future to raise additional capital to fund our operations. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy, or our industry, as well as impact our cash available for distribution.

As of December 31, 2025, we had approximately $20.7 billion of total indebtedness and approximately $19.9 billion of indebtedness net of cash. Our debt could have negative consequences for our financial condition including:

•increasing our vulnerability to general economic and industry conditions;

•requiring a significant portion of our cash flows from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our common stock or to fund our operations, capital expenditures and future business opportunities;

•limiting our ability to enter into long-term power sales or fuel purchases which require credit support;

•limiting our ability to fund operations or future acquisitions;

•limiting our ability to repurchase shares under the share repurchase program;

•restricting our ability to make distributions or pay dividends with respect to our common and preferred stock and the ability of our subsidiaries to make distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;

•inhibiting the growth of our stock price;

•exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under the Vistra Operations Credit Facilities, are at variable rates of interest, only a portion of which are hedged;

•limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and

•limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who may have less debt.

We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace our existing indebtedness on favorable terms or at all upon the expiration or termination thereof. Our failure to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions and limitations that could affect our ability to operate our business, or liquidity, and results of operations, and any failure to comply with these restrictions could have a material adverse effect on us.

The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions that could adversely affect us by limiting our ability to operate our businesses and plan for, or react to, market conditions or to meet our capital needs and could result in an event of default under the Vistra Operations Credit Facilities, indentures and/or our other debt facilities. The Vistra Operations Credit Facilities, indentures and our other debt facilities contain events of default customary for financings of such type. If we fail to comply with the covenants in the Vistra Operations Credit Facilities, indentures and/or our other debt facilities and are unable to obtain a waiver or amendment, or a default exists and is continuing, the lenders under such agreements or notes, as the case may be, could give notice and declare outstanding borrowings thereunder immediately due and payable. The breach of any covenants or obligations in certain agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, not otherwise waived or amended, could result in a default under the applicable debt obligations and could trigger acceleration of those obligations, which in turn could trigger cross defaults under other agreements governing our debt, and any such acceleration of outstanding borrowings could have a material adverse effect on us.

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Certain obligations are required to be secured by letters of credit, surety bonds, first liens, or cash, which increase our costs. If we are unable to provide such security, it may restrict our ability to conduct our business, which could have a material adverse effect on us.

We undertake certain hedging and commodity activities and enter certain financing arrangements with various counterparties that require cash collateral or the posting of letters of credit which are at risk of being drawn down in the event we default on our obligations. We currently use margin deposits, prepayments, surety bonds, U.S. Treasury securities or Treasury Strips, letters of credit and first liens as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices, the use of first lien collateral, and also based on our credit ratings and the general perception of creditworthiness in the markets in which we operate. In the case of commodity arrangements, the amount of such credit support that must be provided is typically based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without enough working capital or other sources of available liquidity to post as collateral, we may not be able to manage price volatility effectively or to implement our strategy. A material increase in the amount of letters of credit or cash collateral required to be provided to our counterparties may have a material adverse effect on us.

We may not be able to consummate the Cogentrix Transactions on the anticipated terms, on the anticipated timeline, or at all, which could adversely affect our business, financial condition, results of operation and stock price.

The consummation of the Cogentrix Transactions (as defined below) remains subject to the satisfaction or waiver of customary closing conditions, including receipt of all requisite regulatory approvals, and expiration or termination of all applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the HSR Act), as well as the satisfaction of other customary conditions set forth in the definitive agreements. The closing of each of the Cogentrix Transactions is also conditioned upon being consummated substantially concurrently. These closing conditions may not be fulfilled in a timely manner or at all, and, accordingly, the Cogentrix Transactions may not be completed.

In connection with the Cogentrix Transactions, a portion of the consideration payable at closing consists of 5,000,000 shares of our common stock. The issuance of these shares will dilute the ownership interests of our existing stockholders. Although the issuance represents a relatively small percentage of our currently outstanding common stock, such dilution could adversely affect the market price of our common stock.

In addition, the definitive agreements provide that either party may terminate the applicable agreement if the Cogentrix Transactions are not completed by December 31, 2026 (which date may be extended twice, in each case, by up to 90 days, as further provided in the definitive agreements). If we are unable to complete the Cogentrix Transactions, we still will incur and will remain liable for significant transaction costs, including legal, accounting, advisory and other costs relating to the Cogentrix Transactions. Also, depending upon the reasons for not completing the Cogentrix Transactions, we may be required to pay Cogentrix Energy a termination fee of, as to the purchase agreement, $77,839,364, and, as to the merger agreement, $72,160,636.

If the Cogentrix Transactions are not consummated, or are consummated on different terms than as contemplated by the definitive agreements, we could be adversely affected and subject to a variety of risks associated with the failure to consummate the Cogentrix Transactions, or to consummate the Cogentrix Transactions as contemplated by the definitive agreements, including:

•our stockholders may be prevented from realizing the anticipated potential benefits of the Cogentrix Transactions;

•the market price of our common stock could decline significantly;

•reputational harm due to the adverse public perception of any failure to successfully complete the Cogentrix Transactions; and

•the attention of our management and employees may be diverted from their day-to-day business and operational matters and our relationships with our customers and suppliers may be disrupted as a result of efforts relating to attempting to consummate the Cogentrix Transactions.

VISTRA CORP.

Following the completion of the Cogentrix Transactions, we may not realize the anticipated synergies and other expected benefits of the Cogentrix Transactions on the anticipated timeline or at all.

Even if the Cogentrix Transactions are completed, we may not realize the anticipated synergies and other expected benefits of the Cogentrix Transactions on the anticipated timeline or at all. The success of the Cogentrix Transactions will depend, in part, on our ability to integrate the Cogentrix assets and operations into our existing business, manage and operate the acquired facilities efficiently, retain key personnel, and effectively manage the increased scale and geographic footprint of our generation portfolio. Further, the acquired assets may be subject to operational, regulatory, environmental, market or other risks that differ from or are greater than those associated with our existing assets, including unanticipated capital expenditure requirements, potential unknown liabilities, or changes in market rules or regulatory requirements applicable to the regions in which the Cogentrix assets operate. We will be required to devote significant management attention and resources to the integration of Cogentrix Energy’s business practices and operations into our existing business.

For all these reasons, it is possible that the integration process could result in the distraction of our management, the disruption of our ongoing business or inconsistencies in operations, services, standards, controls, policies and procedures, any of which could adversely affect our ability to maintain relationships with operators, vendors and employees or to achieve the anticipated benefits of the Cogentrix Transactions. Failure to successfully integrate and operate the acquired assets, or to realize the anticipated benefits of the Cogentrix Transactions could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may not be able to complete future acquisitions, including the pending Cogentrix Transactions, on favorable terms or at all, successfully integrate future acquisitions into our business, or effectively identify and invest in value-creating businesses, assets or projects, which could result in unanticipated expenses and losses or otherwise hinder or delay our growth strategy.

As part of our growth strategy, including our desire to grow our retail platform and diversify and expand our generation assets, we may pursue acquisitions of assets or operating entities. This strategy depends on the Company's ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on favorable terms. Our ability to continue to implement this component of our growth strategy will be limited by our ability to identify appropriate acquisition or joint venture candidates and our financial resources, including available cash and access to capital. In addition, the Company will compete with other companies for these limited acquisition opportunities, which may increase the Company's cost of making acquisitions or limit the Company’s ability to make acquisitions at all. Any expense incurred in completing acquisitions or entering into joint ventures, the time it takes to integrate an acquisition or our failure to integrate acquired businesses successfully could result in unanticipated expenses and losses. Furthermore, we may not be able to fully realize the anticipated benefits from any future acquisitions or joint ventures we may pursue. In addition, the process of integrating acquired operations into our existing operations may involve unknown risks, result in unforeseen operating difficulties and expenses, and may require significant financial resources that would otherwise be available for the execution of our business strategy. If the Company is unable to identify and consummate future acquisitions, it may impede the Company's ability to execute its growth strategy.

VISTRA CORP.

Our ability to achieve the expected growth of our Vistra Zero portfolio, consisting of our solar generation, battery ESS, and other renewables development projects, is subject to substantial capital requirements and other significant uncertainties.

We have a substantial capital allocation plan intended for investments in renewable assets, including solar development projects and battery ESS. As part of our business strategy, we plan to continually assess potential strategic acquisitions or investments in renewable assets, emerging technologies and related projects. Notably, the Company's ability to successfully develop our current renewables projects, or in the future acquire additional renewable assets, may be impacted by the demand for and viability of renewable assets generally, which may vary depending on availability of projects and financing, as well as public policy, financial and tax mechanisms implemented at the state and federal levels to support the development of renewable assets. Various factors could result in increased costs or result in delays or cancellation of our current or future renewable projects, or the loss of, or declines in the value of, our investments in projects including, but not limited to, risks relating to siting, financing, engineering and construction, permitting, interconnection requests, federal and state regulatory approvals, new legislation or regulatory changes impacting the industry, commissioning delays, import tariffs, changes to federal income tax laws, economic events or factors, environmental and community concerns, availability of or requirements for additional funding, enhanced competition, or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. Further, the proliferation of renewable projects has resulted in a large volume of interconnection requests submitted to grid operators, including the markets in which we operate, resulting in significant delays to the approval process and estimated completion dates for our projects and others. FERC and regional ISOs are working to address these backlogs, including with regulatory rule changes, changing the interconnection process, the impacts of which are currently unknown because the changes have only been partially implemented. Additionally, the increased demand for construction of renewables projects, such as battery ESS and solar projects, and other labor market and supply chain constraints have resulted, and may continue to result, in limited availability of qualified specialists, contractors, and necessary services or materials, leading to delays in and higher costs for the development and construction of our current and future planned projects. Should any of these factors occur, our financial position, results of operations, and cash flows could be adversely affected, or our future growth opportunities may not be realized as anticipated.

While certain of our subsidiaries are in various stages of developing and constructing solar generation facilities and battery ESS and certain of these projects have signed long-term contracts or made similar arrangements for the sale of electricity, in other cases, our subsidiaries may enter into obligations in the development process even though the subsidiaries have not yet secured power purchase arrangements or other important elements for a successful project. If the project does not proceed as planned, our subsidiaries may remain obligated for certain liabilities even though the project will not be completed. Development is inherently uncertain and we may forgo certain development opportunities and we may undertake significant development costs before determining that we will not proceed with a particular project. We believe that capitalized costs for projects under development are recoverable; however, any individual project may not be completed or reach commercial operation. If these development efforts are not successful, we may abandon a project under development and write off the costs incurred in connection with such project and could incur additional losses associated with any related contingent liabilities.

Circumstances associated with potential divestitures could adversely affect our results of operations and financial condition.

In evaluating our business and the strategic fit of our various assets, we may determine to sell one or more of such assets. Despite a decision to divest an asset, we may encounter difficulty in finding a buyer willing to purchase the asset at an acceptable price and on acceptable terms and in a timely manner. In addition, a prospective buyer may have difficulty obtaining financing. Divestitures could involve additional risks, including:

•difficulties in the separation of operations and personnel;

•the need to provide significant ongoing post-closing transition support to a buyer;

•management's attention may be temporarily diverted;

•the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;

•the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;

•the disruption of our business; and

•potential loss of key employees.

We may not be successful in managing these or any other significant risks that we may encounter in divesting any asset, which could adversely affect our results of operations and financial condition.

VISTRA CORP.

If our goodwill, intangible assets, or long-lived assets become impaired, we may be required to record a significant charge to earnings.

Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to our retail trade names are not amortized and are subject to impairment testing annually, or when events or changes in the business environment indicate that the carrying value of the reporting unit may exceed its fair value. Additionally, we evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Any reduction in or impairment of the value of goodwill, intangible assets, or other long-lived assets will result in a charge against earnings, which could materially adversely affect our reported results of operations and financial position in future periods.

If an impairment of goodwill, intangible assets with indefinite useful lives, or long-lived assets is realized, it may result in a significant charge to earnings in the respective quarterly or annual financial results prepared in accordance with GAAP.

Issuances or acquisitions of our common stock, or sales or dispositions of our common stock by stockholders, that result in an ownership change as defined in Internal Revenue Code (IRC) §382 could further limit our ability to use certain tax attributes and our federal net operating losses to offset our future taxable income.

If an "ownership change," as defined in Section 382 of the IRC (IRC §382) occurs, the amount of NOLs that could be used in any one year following such ownership change could be substantially limited. In general, an "ownership change" would occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, each of which owns (or is deemed to own under IRC §382) 5 percent or more of such company's stock. Given IRC §382's broad definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is outside our control. Vistra acquired NOLs from its merger with Dynegy; however, Vistra's use of such attributes is limited under IRC §382 because the merger constituted an "ownership change" with respect to Dynegy. If there is an "ownership change" with respect to Vistra (including by the normal trading activity of greater than 5% stockholders), the utilization of all NOLs existing at that time would be subject to additional annual limitations based upon a formula provided under IRC §382 that is based on the fair market value of the Company and prevailing interest rates at the time of the ownership change. In addition, any ownership change with respect to Vistra could result in additional limitations on our ability to use certain tax attributes, including depreciation, existing at the time of any such ownership change and have an impact on our tax liabilities.

Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or increased taxes or fees, could have a material adverse effect on our financial condition, results of operations and cash flows.

We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. Our effective tax rate or tax payments could be adversely affected by these legislative measures. The Inflation Reduction Act (IRA), enacted August 16, 2022, and the One Big Beautiful Bill Act (OBBBA) enacted July 4, 2025, both introduced significant changes to current U.S. federal tax law. For example, the OBBBA includes the enactment of several new proposals, including, but not limited to (i) a reinstatement of 100% accelerated depreciation for certain qualifying expenditures, (ii) an increase in the limit of certain interest that can be deducted by a corporation, (iii) accelerated phase-out of certain renewable energy tax credits associated with solar and wind projects, and (iv) additional requirements to qualify for enhanced renewable energy tax credits. These changes are complex and continue to be the subject of additional guidance issued by the U.S. Treasury and the Internal Revenue Service. In addition, the reaction to the federal tax changes by the individual states continues to evolve. Our interpretations and assumptions around U.S. tax reform may evolve in future periods as further administrative guidance and regulations are issued, which may materially affect our effective tax rate or tax payments.

U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. Our tax positions may not be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations and financial condition.

U.S. federal income tax reform and changes in other tax laws could adversely affect us. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on various aspects of our operations. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees could have a material adverse effect on our financial condition, results of operations and cash flows.

VISTRA CORP.

Regulatory and Legislative Risks

Our businesses are subject to ongoing complex governmental regulations and legislation that have adversely impacted, and may in the future adversely impact, our businesses, results of operations, liquidity, financial condition, and cash flows.

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in power generation and sale of electricity, natural gas, emissions and renewable energy certificates, and other commodities. We attempt to comply with changing legislative and regulatory requirements, but there is a risk that we will fail to adapt to any such changes successfully or on a timely basis. Compliance with, or changes to, the requirements under these legal and regulatory regimes, including those proposed or implemented under the current presidential administration or during any future change of administration, or any repeal of existing beneficial laws or regulations, may adversely impact our businesses, results of operations, liquidity, financial condition, and cash flows.

Our businesses are subject to numerous state and federal laws (including, but not limited to, Texas Public Utility Regulatory Act, the Federal Power Act, the Natural Gas Policy Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act (CAA), the Clean Water Act (CWA), the Resource Conservation and Recovery Act (RCRA), the Energy Policy Act of 2005, the Dodd-Frank Wall Street Reform and the Consumer Protection Act and the Telephone Consumer Protection Act), changing governmental policy and regulatory actions (including those of the FERC, the DOE, the NERC, the RCT, the MSHA, the EPA, the NRC, the DOJ, the FTC, the CFTC, state public utility commissions and state environmental regulatory agencies), and the rules, guidelines and protocols of ERCOT, CAISO, ISO-NE, MISO, NYISO and PJM with respect to various matters, including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, orders from governmental or regulatory agencies requiring continued operation of units beyond their planned retirement dates, development, operation and reclamation of lignite mines, recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition, administrative pricing mechanisms (and adjustments thereto), rates for wholesale sales of electricity, mandatory reliability standards and environmental matters. We, along with other market participants, are subject to electricity pricing constraints and market behavior and other competition-related rules and regulations. Additionally, Ambit's direct selling business (i) could be found by regulators not to be in compliance with applicable law or regulations, which may lead to our inability to obtain or maintain a license, permit, or similar certification and (ii) may be required to alter its compensation practices in order to comply with applicable federal or state law or regulations. Changes in, revisions to, or reinterpretations of, existing laws and regulations may have a material adverse effect on our businesses, results of operations, liquidity, financial condition and cash flows.

Extreme weather events have resulted, and in the future may result, in efforts by both federal and state government and regulatory agencies to investigate and determine the causes of such events. For example, Winter Storm Uri and Winter Storm Elliott led to regulatory requests for information and notices of investigation by NERC, FERC, regional reliability entities, ISOs/RTOs, and independent market monitors for regions across the country. Such investigations have resulted, and in the future may result, in changes in laws or regulations that impact our industry and businesses including, but not limited to, additional requirements for winterization of various facets of the electricity supply chain including generation, transmission, and fuel supply; improvements in coordination among the various participants in the electricity supply chain during any future event; restrictions or limitations on the types of plans permitted to be offered to customers; potential revisions to the method of calculation of market compensation and incentives relating to the continued operation of assets that only run periodically, including during extreme weather events or other times of scarcity; and other potential legislative and regulatory corrective actions that may be taken. Previously announced or future legal proceedings, regulatory actions, or other administrative proceedings involving market participants may lead to adverse determinations or other findings of violations of laws, rules, or regulations, any of which may impact the ability of market participants to satisfy, in whole or in part, their respective obligations. For example, the Texas Legislature, the PUCT, ERCOT, FERC, and NERC have implemented new requirements and continue to consider future market design and other rule changes in response to Winter Storm Uri and other extreme weather events.

VISTRA CORP.

Finally, the regulatory environment has undergone significant changes in the last several years due to state and federal policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new generation. For example, changes to, or development of, legislation that requires the use of clean renewable and alternate fuel sources or mandate the implementation of energy conservation programs that require the implementation of new technologies, could increase our capital expenditures and/or impact our financial condition. Changes enacted by the Texas Legislature through Senate Bill 2627, the Powering Texas Forward Act, to administer Texas Energy Fund (TEF) programs, which include grants and loans to finance the construction, maintenance, modernization, and operation of electric facilities in Texas, may negatively impact our financial condition if it materially changes market fundamentals. Recent proposals in PJM for an out-of-market reliability backstop auction for new dispatchable generation could similarly negatively impact our financial condition if it materially changes market fundamentals. Additionally, in some retail energy markets, state legislators, government agencies and other interested parties have made proposals to change the use of market-based pricing, re-regulate areas of these markets that have previously been competitive, or permit electricity delivery companies to construct or acquire generation facilities. Other proposals to re-regulate the retail energy industry may be made, and legislative or other actions affecting electricity and natural gas deregulation or restructuring process may be delayed, discontinued or reversed in states in which we currently operate or may in the future operate. If such changes were to be enacted by a regulatory body, we may lose customers, incur higher costs and/or find it more difficult to acquire new customers. These changes are ongoing, and we cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on our business.

We are required to obtain, and to comply with, government permits and approvals.

We are required to obtain, and to comply with, numerous permits and licenses from federal, state and local governmental agencies. The process of obtaining and renewing necessary permits and licenses can be lengthy and complex and can sometimes result in the establishment of conditions that make the project or activity for which the permit or license was sought unprofitable or otherwise unattractive. In addition, such permits or licenses may be subject to denial, revocation or modification under various circumstances. Failure to obtain or comply with the conditions of permits or licenses, or failure to comply with applicable laws or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our delivery of electricity to our customers and may subject us to penalties and other sanctions. Renewal of our existing permits or licenses could be denied or jeopardized by various factors, including (a) failure to provide adequate financial assurance for closure, (b) failure to comply with environmental, health and safety laws and regulations or permit conditions, (c) local community, political or other opposition and (d) executive, legislative or regulatory action.

Our inability to procure and comply with the permits and licenses required for our operations, or the cost to us of such procurement or compliance, could have a material adverse effect on us. In addition, new environmental legislation or regulations, if enacted, or changed interpretations of existing laws, may cause activities at our facilities to need to be changed to avoid violating applicable laws and regulations or elicit claims that historical activities at our facilities violated applicable laws and regulations. In addition to the possible imposition of fines in the case of any such violations, we may be required to undertake significant capital investments and obtain additional operating permits or licenses, which could have a material adverse effect on us.

Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.

We are subject to extensive environmental regulation by governmental authorities, including federal and state environmental agencies and/or attorneys general. We may incur significant additional costs beyond those currently contemplated to comply with these regulatory requirements. If we fail to comply with these regulatory requirements, we could be subject to administrative, civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions and CCR, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements. Any of the foregoing could have a material adverse effect on us.

VISTRA CORP.

The Biden Administration finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities. At present, many of those regulatory actions have been abated while the Trump Administration reviews those regulatory actions and promulgates new proposals. In the future, the EPA may also propose and finalize additional regulatory actions that may adversely affect our existing generation facilities or our ability to cost-effectively develop new generation facilities. The currently installed emissions control equipment at our lignite, coal and/or natural gas-fueled generation facilities may not satisfy the requirements under any future EPA or state environmental regulations. Some of the recent regulatory actions, such as the EPA's Good Neighbor Plan for the 2015 Ozone NAAQS, the final rule to regulated GHG emissions that would replace the ACE rule, and actions under the Regional Haze program, if not repealed, altered, or invalidated by the courts could require us to install significant additional control equipment, resulting in potentially material costs of compliance for our generation units, including capital expenditures, higher operating and fuel costs and potential production curtailments or plant retirements. These costs or operation impacts could have a material adverse effect on us. In January 2025, President Trump issued a series of executive orders, including an order titled Unleashing American Energy (the "Order") that ordered that all federal agencies are to review all existing regulations, orders and other actions for consistency with the policy goals in that Order, and develop an action plan within 30 days to resolve any policy inconsistencies. In addition, the Order stated that the U.S. Attorney General may request stays of litigation involving any identified rules or actions from the review. The Trump Administration is reviewing the actions of the Biden Administration, but the outcome of those actions is uncertain.

We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approval is retroactively disallowed or adversely modified, the operation of our generation facilities could be stopped, disrupted, curtailed or modified or become subject to additional costs. Any such stoppage, disruption, curtailment, modification or additional costs could have a material adverse effect on us.

In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased, developed or sold, regardless of when the liabilities arose and whether they are now known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us, which could have a material adverse effect on us.

VISTRA CORP.

We could be materially and adversely affected if new federal or state legislation or regulations are adopted to address global climate change, or if existing regulations are vacated, stayed, revised or re-proposed, that could require efforts that exceed or are more expensive than our currently planned initiatives or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.

There is continuing emphasis nationally and internationally on global climate change and how GHG emissions, such as CO2, contribute to global climate change. Over the last several years, the U.S. Congress has considered and debated several proposals intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the development of low-carbon technology and federal renewable portfolio standards. In July 2019, the EPA finalized the ACE rule that developed emissions guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generation units. In January 2021, the ACE rule was vacated by the D.C. Circuit Court and remanded to the EPA for further consideration in accordance with the court's ruling. The D.C. Circuit Court's decision was appealed to the U.S. Supreme Court. In June 2022, the U.S. Supreme Court issued its decision in West Virginia v. EPA, in which it held that the EPA does not have the authority to apply generation shifting in the regulation of GHG emissions. The judgment reversed the D.C. Circuit Court's decision and remanded the case for further proceedings consistent with the U.S. Supreme Court's opinion. In May 2024, the EPA issued a more stringent and more encompassing rule to replace the ACE rule. In June 2025, the EPA proposed to repeal the GHG rule issued in May 2024, and the rule remains subject to ongoing legal challenges in the D.C. Circuit after the U.S. Supreme Court declined to issue a stay of that rule, but that litigation is currently abated. As a result, the scope, timing and ultimate requirements of any federal regulation of GHG emissions from existing power generation facilities remains uncertain. Additionally, in February 2026, the EPA issued a rule that repeals the agency's prior 2009 endangerment finding for all GHG emission standards for light-, medium-, and heavy-duty vehicles. The rescission of the endangerment finding does not impact power plants, however, the EPA has also stated that, for other rules that have relied on the endangerment finding, it intends to initiate other rulemakings to address any overlapping issues. Several environmental groups have filed a challenge to the EPA's repeal of the endangerment finding in the D.C. Circuit Court. Regulatory uncertainty resulting from changes in administration priorities, judicial review and enforcement approaches may complicate long-term capital planning, asset retirement decisions and investments in new technologies, even if regulatory requirements are delayed, modified or repealed. In addition, a number of federal court cases have been filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (including us) that produce GHG emissions. We could be materially and adversely affected if federal and/or state legislation or regulations that address global climate change require efforts that exceed or are more expensive than our currently planned initiatives, or if regulatory uncertainty itself results in increased costs or inefficiencies, or if we are subject to lawsuits for alleged damage to persons or property resulting from GHG emissions.

Luminant's mining operations are subject to RCT oversight.

We currently own and operate, or are in the process of reclaiming, various surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. We also own or lease, and are in the process of reclaiming, multiple waste-to-energy surface facilities in Pennsylvania. The RCT, which exercises broad authority to regulate reclamation activity, reviews on an ongoing basis whether Luminant is compliant with RCT rules and regulations and whether it has met all the requirements of its mining permits in Texas. Any new rules and regulations adopted by the RCT or the Department of Interior Office of Surface Mining, which also regulates mining activity nationwide, or any changes in the interpretation of existing rules and regulations, could result in higher compliance costs or otherwise adversely affect our financial condition or cause a revocation of a mining permit. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities.

Luminant's lignite mining reclamation activity will require significant resources as existing and retired mining operations are reclaimed over the next several years.

In conjunction with Luminant's announcements in 2017 to retire several power generation assets and related mining operations, along with the reclamation obligations at the closed Martin Lake mines and continuous reclamation activity at its continuing mining operations for its mines related to the Oak Grove generation asset, Luminant is expected to spend a significant amount of money, internal resources and time to complete the required reclamation activities. For the next five years, Vistra is projected to spend approximately $182 million (on a nominal basis) to achieve its mining reclamation objectives.

VISTRA CORP.

Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us.

We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment, commercial, and environmental issues, and other claims for injuries and damages. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, potential losses. Based on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on us. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a significant business risk.

We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk of additional regulatory investigations or administrative proceedings. As we adopt new technologies, like AI, there is a risk that the content, analyses, recommendations, or judgments that AI applications assist in producing are alleged to be deficient, inaccurate, biased, or infringe on other's rights or property interests. Any such regulatory investigation or administrative proceeding could result in us incurring penalties and other costs which may have a material adverse effect on us.

Our retail businesses, which each have REP certifications that are subject to review of the public utility commissions in the states in which we operate, are subject to changing state rules and regulations that could have a material impact on the profitability of our business.

The competitiveness of our U.S. retail businesses partially depends on state regulatory policies that establish the structure, rules, terms and conditions on which services are offered to retail customers. Specifically, the public utility commissions and/or the attorney generals of the various jurisdictions in which the Retail segment operates may at any time initiate an investigation into whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for REP certification, including financial requirements. These state policies and investigations, which can include controls on the retail rates our retail businesses can charge, the imposition of additional costs on sales, restrictions on our ability to obtain new customers through various marketing channels and disclosure requirements, investigations into whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for REP certification, including financial requirements, can affect the competitiveness of our retail businesses. Any removal or revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers in the applicable jurisdiction, and such decertification could have a material adverse effect on us. Additionally, state or federal imposition of net metering or renewable portfolio standard programs can make it more or less expensive for retail customers to supplement or replace their reliance on grid power. Our retail businesses may have limited ability to influence development of these state rules, regulations and policies, and our business model may be more or less effective, depending on changes to the regulatory environment.

Operational Risks

Volatile power supply costs and demand for power have and could in the future adversely affect the financial performance of our retail businesses.

We are the primary provider of our retail businesses' wholesale electricity supply requirements, but our retail businesses purchase a portion of their supply requirements from third parties. As a result, the financial performance of our retail business depends on their ability to obtain adequate supplies of electric generation from third parties at prices below the prices they charge their customers. Consequently, our earnings and cash flows could be adversely affected in any period in which the retail businesses' wholesale electricity supply costs rise at a greater rate than the rates they charge to customers. The price of wholesale electricity supply purchases associated with the retail businesses' energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:

•varying supply procurement contracts used and the timing of entering into related contracts;

•subsequent changes in the overall price of natural gas;

•daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;

•transmission constraints and the Company's ability to move power to our customers;

•out-of-market payments, uplifts, or other non-pass through charges, and

VISTRA CORP.

•changes in Market Heat Rate.

The retail businesses' earnings and cash flows could also be adversely affected in any period in which their customers' actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors, transmission and distribution outages, demand-side management programs, competition and economic conditions, or extreme weather events, such as Winter Storm Uri in February 2021.

Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing customers and the inability to attract new customers.

We operate in a very competitive retail market where our retail operation faces significant competition for customers. We believe our brands are viewed favorably in these markets, but despite our commitment to providing superior customer service and innovative products, customer sentiment toward our brands, including by comparison to our competitors' brands, depends on certain factors beyond our control. For example, competitor REPs may offer different products, lower electricity prices and other incentives, which, despite our long-standing relationship with many customers, may attract customers away from us. If we are unable to successfully compete with competitors in the retail market it is possible our retail customer counts could decline, which could have a material adverse effect on us.

As we try to grow our retail business and operate our business strategy, we compete with various other REPs that may have certain advantages over us. For example, in new markets, our principal competitor for new customers may be the incumbent REP, which has the advantage of long-standing relationships with its customers, including well-known brand recognition. In addition to competition from the incumbent REP, we may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with us. Some of these competitors or potential competitors may be larger than we are or have greater resources or access to capital than we have. Competitors may also incorporate emerging technology like generative AI into their businesses, services, and products more quickly or more successfully than we do. In retail markets with substantial competition, high customer acquisition costs may outweigh the potential margin and it may not be profitable for us to compete in these markets.

Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, our customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material adverse effect on us.

The substantial majority of our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered and we may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area or, with respect to capacity performance in PJM and performance incentives in ISO-NE, we may be subject to significant penalties. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower operating margins. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service. Any of the foregoing could have a material adverse effect on us.

Cybersecurity attacks or technology systems failures could disrupt business operations and expose us to significant liabilities, reputational damage, loss of customers, and regulatory action.

Our businesses depend on the secure and reliable storage, processing and communication of electronic data and sophisticated computer hardware and software systems. Our information technology systems and infrastructure, and those of our vendors and suppliers, face constant threats that have in the past and could in the future compromise data confidentiality, integrity, or availability. While we have controls in place designed to protect our information technology (IT) infrastructure, such breaches and threats are becoming increasingly sophisticated and complex, requiring the continuing evolution of our program. A breach or similar IT incident could interrupt normal business operations and affect our ability to use our generation assets, customer information, or communication systems, which could have a material adverse effect on us.

Potential disruptions from cyber/data and physical security breaches to "critical cyber assets" that interrupt the delivery of power to the Bulk Electric System could incur significant penalties per violation for failure to comply with mandatory electric reliability standards by FERC under the Energy Policy Act of 2005.

VISTRA CORP.

Further, our retail business requires us to regularly access, collect, store, and transmit customer data, including sensitive customer data. New data privacy and data protection laws and regulations, increased enforcement, and other government actions could impact our businesses, increase compliance costs, and failure to comply with these laws and regulations could adversely affect our business and financial results. Our retail business may need to provide access to customer data, including sensitive customer data, to third parties and service providers to provide services, such as call center operations. In certain circumstances, Vistra could incur liability for a third-party or service provider's misuse or loss of the data.

We take precautions to protect our infrastructure, but we have been, and will likely continue to be, subject to attempts at phishing and other cybersecurity intrusions. International conflict increases the risk of state-sponsored cyber threats and escalated use of cybercriminal and cyber-espionage activities. In particular, the current geopolitical climate has further escalated cybersecurity risk, with various government agencies, including the Federal Bureau of Investigation (FBI) and the U.S. Cybersecurity & Infrastructure Security Agency, issuing warnings of increased cyber threats, particularly for U.S. critical infrastructure. As of the date of this report, the Company has not identified a cyber/data event causing any material operational, reputational or financial impact. However, we recognize the growing threat within the general marketplace and our industry, especially as generative AI becomes more widely used by threat actors and we may not be able to prevent or mitigate any such impacts in the future. In the event of a material cyber breach, critical operational capabilities to support our generation, commercial, or retail operations could be disrupted or lost. Additionally, customer, confidential, or proprietary data could be compromised, misused, or inappropriately disclosed. If critical operational capabilities or data were impacted, it could adversely affect our reputation, diminish customer confidence, expose us to legal or regulatory claims, impair our business strategy, or impact our results of operation or financial condition, which could have a material adverse effect on us. Our efforts to deter, identify, and mitigate future breaches may require additional, significant capital and operating costs and may not be successful.

We may suffer material losses, costs and liabilities due to operation risks, regulatory risks, and the risk of nuclear accidents arising from the ownership and operation of the nuclear generation facilities.

We own and operate nuclear generation facilities in Texas, Ohio, and Pennsylvania. The ownership and operation of nuclear generation facilities involves certain risks. These risks include:

•unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity, insider threat, third-party compromise or other problems;

•inability to effectively complete nuclear power uprates on terms, cost, or schedule contemplated by current forecasts or customer agreements;

•inadequacy or lapses in maintenance protocols;

•the impairment of reactor operation and safety systems due to human error or force majeure;

•the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials;

•the costs of procuring nuclear fuel, including impacts from trade restrictions such as tariffs, embargoes, and quotas (see Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations – Business Environment and Outlook);

•the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;

•terrorist or cybersecurity attacks by nation-states or other threat actors and the cost to protect and recover against any such attack;

•the impact of a natural disaster;

•financial risk associated with retrospective insurance premium that could become due under secondary coverage required by the Price Anderson Act;

•limitations on the amounts and types of insurance coverage commercially available; and

•uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives.

Our financial performance could be materially and negatively affected by matters arising from our ownership and operation of nuclear facilities, including any prolonged unavailability of any of our nuclear generation facilities. The following are among the more significant related risks:

•Operational Risk. Operations at any generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur at a nuclear generation facility, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at our nuclear generation facilities.

VISTRA CORP.

•Regulatory Risk. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

•Spent Nuclear Fuel Storage. Our nuclear operations produce various types of nuclear waste materials, including spent nuclear fuel. The availability of a national repository for the storage of spent nuclear fuel and the timing of that facility opening will significantly affect the costs associated with storage of spent nuclear fuel and the ultimate amounts received from the DOE to reimburse us for these costs. Any regulatory action relating to the timing and availability of a repository for spent nuclear fuel could adversely affect our ability to decommission fully our nuclear units. We cannot predict whether a fee may be established or to what extent in the future for spent nuclear fuel disposal.

•Decommissioning Obligation and Funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.

Actual costs to decommission our nuclear facilities may substantially exceed our estimates as a result of changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in federal or state regulatory requirements, other changes in our estimates or ability to effectively execute on our planned decommissioning activities.

Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. In addition, financial market performance directly affects the asset values in the NDT trust funds. If the investments held by our PJM NDT funds are not sufficient to fund the decommissioning of our nuclear units, we could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.

•Nuclear Accident Risk. Although the safety record of our nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred at nuclear stations both in the U.S. and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property damage. Any accident, or perceived accident, could result in significant liabilities that may exceed our resources, including insurance coverages, and could damage our reputation. Such liabilities to third parties are currently covered by a primary layer of financial protection required by the Price Anderson Act in the form of insurance carried by the owners of each nuclear facility and by a secondary layer of insurance coverage into which each nuclear licensee in the country is required to contribute in the event of an accident at any facility which exceeds the primary level of coverage for that facility. Our potential exposure for the secondary layer of coverage is currently capped at $165.9 million per reactor but is subject to adjustment for inflation, and the total retrospective premium per reactor per incident is capped at $24.7 million in any one year. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately result in the suspension or termination of power generation from the impacted facility. Such accidents could also result in property damage to our nuclear plant and equipment, which could exceed coverage available under insurance provided by Nuclear Electric Insurance Limited. If a serious nuclear incident were to occur, our business, reputation, financial condition and results of operations could be materially adversely affected.

VISTRA CORP.

The operation and maintenance of power generation facilities and related mining operations are capital intensive and involve significant risks that could adversely affect our results of operations, liquidity and financial condition.

The operation and maintenance of power generation facilities and related mining operations involve many risks, including, as applicable, start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source, the ability to timely obtain parts for equipment repairs, the inability to transport our product to our customers in an efficient manner due to the lack of transmission capacity or the impact of unusual or adverse weather conditions or other natural events, or terrorist attacks, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in substantial lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. Older generation equipment, even if maintained or refurbished in accordance with good engineering practices, may require significant capital expenditures to operate at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all our generation facilities, (b) any unexpected failure to generate power, including failure caused by equipment breakdown or unplanned outage (whether by order of applicable governmental regulatory authorities, the impact of weather events or natural disasters or otherwise), (c) damage to facilities due to storms, natural disasters, wars, terrorist or cybersecurity attacks, including nation-state attacks or organized cybercrime and other catastrophic events and (d) the passage of time and normal wear and tear. Further, our ability to successfully and timely complete routine maintenance or other capital projects at our existing facilities is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs or losses and write downs of our investment in the project.

We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs. The unexpected requirement of large capital expenditures could have a material adverse effect on us. Moreover, if we significantly modify a unit, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the CAA, which would likely result in substantial additional capital expenditures.

In addition, unplanned outages at any of our generation facilities, whether because of equipment breakdown or otherwise, typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or non-performance penalties or require us to incur significant costs as a result of running one of our higher cost units or to procure replacement power at spot market prices in order to fulfill contractual commitments. If we do not have adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to the volatility of spot markets, which could have a material adverse effect on us. Further, our inability to operate our generation facilities efficiently, manage capital expenditures and costs, and generate earnings and cash flows from our asset-based businesses could have a material adverse effect on our results of operations, financial condition or cash flows. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or non-performance by contractors or vendors.

Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on our revenues and results of operations, and we may not have adequate insurance to cover these risks and hazards. Our employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of our operations.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as extreme weather, earthquake, flood, lightning, hurricane and wind, other human-made hazards, such as nuclear accidents, dam failure, gas or other explosions, mine area collapses, fire, structural collapse, machinery failure, and other dangerous incidents are inherent risks in our operations. These and other hazards have and may in the future cause significant personal injury or loss of life, severe damage to and destruction of property, plant, and equipment, contamination of, or damage to, the environment and suspension of operations. Further, our employees and contractors work in, and customers and the general public may be exposed to, potentially dangerous environments at or near our operations. As a result, employees, contractors, customers, and the general public are at risk for serious injury, including loss of life.

VISTRA CORP.

The occurrence of any one of these events has in the past and may in the future result in us being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject and, even if we do have insurance coverage for a particular circumstance, we may be subject to a large deductible and maximum cap. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, including increasing pressure on firms that provide insurance to companies that own and operate fossil fuel generation, we cannot provide any assurance that our insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.

We have been and may in the future be materially and adversely affected by obligations to comply with federal and state regulations, laws, and other legal requirements that govern the operations, assessments, storage, closure, corrective action, disposal and monitoring relating to CCR.

As a result of electricity produced for decades at coal-fueled power plants in Illinois, Texas and Ohio, we manage large amounts of CCR material in surface impoundments. In addition to the federal requirements under the CCR rule, CCR surface impoundments will continue to be regulated by existing state laws, regulations and permits, as well as additional legal requirements that may be imposed in the future. These federal and state laws, regulations and other legal requirements may require or result in additional expenditures, increased operating and maintenance costs and/or result in closure of certain power generation facilities, which could affect the results of operations, financial position and cash flows of the Company. We have recognized ARO liabilities related to these CCR-related requirements based on costs of closure methods that our operations and environmental services teams determined were appropriate based on the existing closure requirements at the time we recorded those ARO liabilities, and is reasonably possible for those to increase once the IEPA determines final closure requirements for our Illinois sites. As the closure and CCR management work progresses and final closure plans and corrective action measures are developed and approved at each site, the scope and complexity of work and the amount of CCR material could be greater than current estimates and could, therefore, materially impact earnings through increased compliance expenditures.

During the prior administration, the EPA was directed to review a number of environmental rules, including the CCR rule, the ELG rule, the ACE rule and the particulate matter (PM), and NAAQS rules. All of these rules may significantly and adversely impact our existing coal fleet and may lead to accelerated plant closure timeframes. In January 2025, President Trump issued an executive Order, which among other things, requires the EPA to review many of the rules issued during the Biden Administration and authorizes the U.S. Attorney General to request a stay of related litigation while the EPA conducts its review. As a result, the scope, timing, interpretation and enforcement of CCR and other environmental requirements remain subject to change.

The scope and cost of CCR pond closure work could increase significantly based on new or potential requirements imposed by the EPA or state agencies, including the EPA's interpretations on requirements for closure of CCR units. Our current assumptions for closure activities may not be accepted by the EPA or state agencies.

The availability and cost of emission allowances could adversely impact our costs of operations.

We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO2, CO2, and NOX to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet the obligations imposed on us by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances or install costly new emission controls. As we use the emission allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.

VISTRA CORP.

We have been and may in the future be materially and adversely affected by the effects of extreme weather conditions and seasonality.

We have been and may in the future be materially affected by weather conditions and our businesses may fluctuate substantially on a seasonal basis as the weather changes. In addition, we are subject to the effects of extreme weather conditions, including sustained or extreme cold or hot temperatures, hurricanes, floods, droughts, storms, fires, earthquakes or other natural disasters, which could stress our generation facilities and grid reliability, limit our ability to procure adequate fuel supply, or result in outages, damage or destroy our assets and result in casualty losses that are not ultimately offset by insurance proceeds, and could require increased capital expenditures or maintenance costs, including supply chain costs.

Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, certain extreme weather events have previously affected, and may in the future, affect, the availability of generation and transmission capacity, limiting our ability to source or deliver power where it is needed or limit our ability to source fuel for our plants, including due to damage to rail or natural gas pipeline infrastructure. Additionally, extreme weather has resulted, and may in the future result, in (i) unexpected increases in customer load, requiring our retail operation to procure additional electricity supplies at wholesale prices in excess of customer sales prices for electricity, (ii) the failure of equipment at our generation facilities, (iii) a decrease in the availability of, or increases in the cost of, fuel sources, including natural gas, diesel and coal, or (iv) unpredictable curtailment of customer load by the applicable ISO/RTO in order to maintain grid reliability, resulting in the realization of lower wholesale prices or retail customer sales. For example, Winter Storm Uri in February 2021 had a material impact on our results of operations.

Additionally, climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our operations and cause us to incur significant costs to prepare for or respond to these effects.

Weather conditions, which cannot be reliably predicted, could have adverse consequences by requiring us to seek additional sources of electricity when wholesale market prices are high or to sell excess electricity when market prices are low, as well as significantly limiting the supply of, or increasing the cost of our fuel supply, each of which could have a material adverse effect on our business, results of operations, financial condition and liquidity.

Events outside of our control, including an epidemic or outbreak of an infectious disease may materially adversely affect our business.

We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease, or any other public health crisis may cause disruptions to our business and operational plans, as a result of a number of factors, including (a) a protracted slowdown of broad sectors of the economy, (b) changes in demand or supply for commodities, (c) significant changes in legislation or regulatory policy to address the pandemic (including prohibitions on certain marketing channels, moratoriums or conditions on disconnections or limits or restrictions on late fees), (d) reduced demand for electricity (particularly from commercial and industrial customers), (e) increased late or uncollectible customer payments, (f) negative impacts on the health of our workforce, (g) a deterioration of our ability to ensure business continuity (including increased vulnerability to cyber and other information technology risks), and (h) the inability of the Company's contractors, suppliers, and other business partners to fulfill their contractual obligations.

VISTRA CORP.

Changes in technology, increased electricity conservation efforts, or energy sustainability efforts may reduce the value of our business, introduce new or emerging risks, and may otherwise have a material adverse effect on us.

If we cannot adopt technological developments on a timely basis, demand for our services may decline, or we may face challenges in implementing or evolving our business strategy. Significant technological changes continue to impact our industry. To grow and remain competitive, we will need to adapt to changes in available technology like generative AI, continually invest in our assets, increase generation capacity, increase our use of low-carbon technologies, enhance our existing offerings, and introduce new offerings to meet our current and potential customers’ changing service demands. Competitors may incorporate new technologies into their businesses, services, and products more quickly or more successfully than we do. Adopting new and sophisticated technologies may result in implementation issues, such as scheduling and supplier delays, unexpected or increased costs, technological constraints, regulatory issues, customer dissatisfaction, and other issues that could cause delays in launching new technological capabilities. This, in turn could result in significant costs or reduce the anticipated benefits of the technology change. As we adopt new technologies, like AI, there is a risk that the content, analyses, recommendations, or judgments that AI applications assist in producing are alleged to be deficient, inaccurate, biased, or infringe on other’s rights or property interests. Our new services could fail to retain or gain acceptance in the marketplace, or costs associated with these services could be higher than anticipated. As such, our adoption of technology or failure to adopt technology could have a material adverse effect on our business, brand, financial condition, business strategy, and operating results.

Technological advances have improved, and are likely to continue to improve, for existing and alternative methods to produce and store power, including natural gas turbines, wind turbines, fuel cells, hydrogen, micro turbines, photovoltaic (solar) cells, batteries, concentrated solar thermal devices, novel nuclear technologies (including small modular reactors), geothermal energy (including enhanced geothermal systems and advanced geothermal systems), and long duration energy storage, along with improvements in traditional technologies. Such technological advances may be superior to, or may not be compatible with, some of our existing technologies, investments and infrastructure, and may require us to make significant expenditures to remain competitive, and have resulted, and are expected to continue to reduce the costs of power production or storage, which may result in the obsolescence of certain of our operating assets. Consequently, the value of our more traditional generation assets could be significantly reduced as a result of these competitive advances, which could have a material adverse effect on us and our future success will depend, in part, on our ability to anticipate and successfully adapt to technological changes, to offer services and products that meet customer demands and evolving industry standards. In addition, changes in technology have altered, and are expected to continue to alter, the channels through which retail customers buy electricity (i.e., self-generation or distributed-generation facilities). To the extent self-generation or distributed generation facilities become a more cost-effective option for customers, our financial condition, operating cash flows and results of operations could be materially and adversely affected.

Technological advances in demand-side management, large-scale residential or commercial virtual power plants, and increased conservation efforts could result in a decrease in electricity demand. A significant decrease in electricity demand as a result of such efforts would significantly reduce the value of our generation assets. Effective power conservation by our customers could result in reduced electricity demand or significantly slow the growth in such demand. Any such reduction in demand could have a material adverse effect on us. Furthermore, we may incur increased capital expenditures if we are required to increase investment in conservation measures. Additionally, increased governmental and consumer focus on energy sustainability efforts, including desire for, or incentives related to, the development, implementation and usage of low-carbon technology, may result in decreased demand for the traditional generation technologies that we currently own and operate.

We may potentially be affected by emerging technologies that may over time affect change in capacity markets and the energy industry overall.

Emerging technologies such as distributed renewable energy technologies, energy efficiency, electric vehicles, distributed generation, energy storage devices, fuel cells, nuclear small modular reactors, and linear generators could have a significant impact on the energy industry. Additionally, large-scale cryptocurrency mining, AI data centers, and increased industrial electrification are becoming increasingly prevalent in certain markets, including ERCOT, and many of these facilities are "behind-the-meter." Such emerging technologies could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. These emerging technologies may also affect the financial viability of utility counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material adverse effect on our financial condition, results of operations and cash flows.

VISTRA CORP.

The loss of the services of our "key" management and personnel could adversely affect our ability to successfully operate our businesses.

Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside of our industry, government entities and other organizations. Potential difficulties in attracting and retaining highly qualified, skilled employees could restrict our ability to adequately support our business needs and/or result in increased personnel costs. In addition, effective succession planning is important to our long-term success. Failure to timely and effectively ensure transfer of knowledge and smooth transitions involving senior management and other key personnel could hinder our strategic planning and execution.

We could be materially and adversely impacted by strikes or work stoppages by our unionized employees.

As of December 31, 2025, we had approximately 1,860 employees covered by collective bargaining agreements. The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal-, natural gas- and nuclear-fueled generation operation, as well as some battery operations, expire on various dates between February 2026 and March 2029, but remain effective thereafter unless and until terminated by either party. In the event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or outages. We have in place strike contingency plans that address the procurement of replacement labor. Strikes, work stoppages or the inability to negotiate current or future collective bargaining agreements on favorable terms or at all could have a material adverse effect on us.

Risks Related to Our Structure and Ownership of our Common Stock

Vistra is a holding company and its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities of its subsidiaries.

Vistra is a holding company that does not conduct any business operations of its own. As a result, Vistra's cash flows and ability to meet its obligations are largely dependent upon the operating cash flows of Vistra's subsidiaries and the payment of such operating cash flows to Vistra in the form of dividends, distributions, loans or otherwise. These subsidiaries are separate and distinct legal entities from Vistra and have no obligation (other than any existing contractual obligations) to provide Vistra with funds to satisfy its obligations. Any decision by a subsidiary to provide Vistra with funds to satisfy its obligations, whether by dividends, distributions, loans or otherwise, will depend on, among other things, such subsidiary's results of operations, financial condition, cash flows, cash requirements, contractual prohibitions and other restrictions, applicable law and other factors. The deterioration of income from, or other available assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make other distributions to Vistra.

Evolving expectations from stakeholders, including investors, on sustainability issues, including climate risk, and erosion of stakeholder trust or confidence could influence actions or decisions about our company and our industry and could adversely affect our business, operations, financial results or stock price.

Companies across all industries face evolving expectations or scrutiny from stakeholders related to their approach to sustainability matters. For Vistra, reliability, affordability, climate risk, safety, and stakeholder relations remain primary focus areas, and changing expectations of our practices and performance across these and other sustainability areas may impose additional costs or create exposure to new or additional risks. Our operations, projects and growth opportunities require us to have strong relationships with key stakeholders, including local communities and other groups directly impacted by our activities, as well as governments and government agencies, investor advocacy groups, certain institutional investors, investment funds and others which may be focused on sustainability practices. Certain financial institutions have announced policies to presently or in the future cease investing or to divest investments in companies that derive any or a specified portion of their income from, or have any or a specified portion of their operations in, coal and/or other fossil fuels.

We are strategically focused on meeting growing demand for electricity as we prioritize reliability and affordability while being mindful of stakeholder interest in our plans to reduce our carbon footprint. As we work through this transition, our prioritization of reliability and affordability may prevent us from achieving our targets as expected, which could impact stakeholder trust and confidence. Any such erosion of stakeholder trust and confidence, evolving expectations from stakeholders on such sustainability issues, and such parties' resulting actions or decisions about our company and our industry could have negative impacts on our business, operations, financial results, and stock price.

VISTRA CORP.

We may not pay any dividends on our common stock in the future, and we may not realize the anticipated benefits of our share repurchase program.

The Board has adopted a dividend program. Each dividend under the program will be subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, our results of operations, financial condition and liquidity, contractual prohibitions and other restrictions with respect to the payment of dividends. The Board may not declare, and we may not pay, any dividends on our common stock in the future.

The Board has approved a share repurchase program in an aggregate authorized amount of $7.75 billion. Under this share repurchase program or any other future share repurchase programs, we may make share repurchases through a variety of methods, including open market share purchases or privately negotiated transactions. The timing and amount of repurchases, if any, will depend on factors such as the stock price, economic and market conditions, and corporate and regulatory requirements. Any failure to repurchase shares after we have announced our intention to do so may negatively impact our reputation, investor confidence and the price of our common stock.

Holders of our preferred stock may have interests and rights that are different from our common stockholders.

We are permitted under our certificate of incorporation to issue up to 100,000,000 shares of preferred stock. We can issue shares of our preferred stock in one or more series and can set the terms of the preferred stock without seeking any further approval from our common stockholders. Any preferred stock that we issue may rank ahead of our common stock in terms of dividend priority or liquidation premiums and may have greater voting rights than our common stock, which could dilute the value of our common stock to current stockholders and could adversely affect the market price of our common stock. As of December 31, 2025, 1,000,000 shares of Series A Preferred Stock, 1,000,000 shares of Series B Preferred Stock, and 476,066 shares of Series C Preferred Stock were issued and outstanding. The Preferred Stock represents a perpetual equity interest in the Company and, unlike our indebtedness, will not give rise to a claim for payment of a principal amount at a particular date; provided, the Company may redeem the Preferred Stock at the specified times (or upon certain specified events) at the applicable redemption price set forth in the certificate of designation of each of the Series A Preferred Stock, Series B Preferred Stock, and Series C Preferred Stock, respectively (Certificates of Designation). The Preferred Stock is not convertible into or exchangeable for any other securities of the Company. Upon the liquidation, dissolution or winding up of the Company, whether voluntary or involuntary, after payment or provision for payment of the debts and other liabilities of the Company, the holders of Preferred Stock will be entitled to receive, pro rata and in preference to the holders of any other capital stock, an amount per share equal to $1,000 plus accrued and unpaid dividends thereon, if any.

Unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A Preferred Stock, the holders of at least two-thirds of the outstanding Series B Preferred Stock and the holders of at least two-thirds of the outstanding Series C Preferred Stock, each voting as a separate class, we may not adopt any amendment to our certificate of incorporation (including the applicable Certificates of Designation) that would have a material adverse effect on the powers, preferences, duties, or special rights of such series of Preferred Stock, subject to certain exceptions. In addition, unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A Preferred Stock, the holders of at least two-thirds of the outstanding Series B Preferred Stock and the holders of at least two-thirds of the outstanding Series C Preferred Stock, voting as a class together with the holders of any parity securities upon which like voting rights have been conferred and are exercisable, we may not: (i) create or issue any senior securities, (ii) create or issue any parity securities (including any additional Preferred Stock) if the cumulative dividends payable on the outstanding Preferred Stock (or parity securities, if applicable) are in arrears; (iii) create or issue any additional Preferred Stock or any parity securities with an aggregate liquidation preference, together with the issued and outstanding Preferred Stock and any parity securities that are then outstanding, of greater than $2.5 billion, and (iv) engage in any Transaction that results in a Covered Disposition (as such terms are defined in the Certificates of Designation).

VISTRA CORP.

In addition, holders of the Preferred Stock are entitled to receive, when, as, and if declared by our Board, semi-annual cash dividends on the Preferred Stock, which are cumulative from the applicable initial issuance date of the Preferred Stock and payable in arrears, and unless full cumulative dividends have been or contemporaneously are being paid or declared on the Preferred Stock, we may not (i) declare or pay any dividends on any junior securities, including our common stock, or (ii) redeem or repurchase any parity securities or junior securities, subject to limited exceptions set forth in the Certificates of Designation. The Board may not declare, and we may not pay, any dividends on our Preferred Stock in the future. The holders of Preferred Stock (along with any parity securities then outstanding with similar rights) are entitled to elect two additional directors in the event any dividends on Preferred Stock are in arrears for three or more semi-annual dividend periods (whether or not consecutive), and such directors may have competing and different interests to those elected by our common stockholders. The dividend rate for the Series A Preferred Stock from and including the initial issuance date of October 15, 2021 until the first reset date of October 15, 2026 will be 8.0% per annum of the $1,000 liquidation preference per share of Series A Preferred Stock. The dividend rate for the Series B Preferred Stock from and including the initial issuance date of December 10, 2021 until the first reset date of December 15, 2026 will be 7.0% per annum of the $1,000 liquidation preference per share of Series B Preferred Stock. The dividend rate for the Series C Preferred Stock from and including the initial issuance date of December 29, 2023 until the first reset date of January 15, 2029 will be 8.875% per annum of the $1,000 liquidation preference per share of Series C Preferred Stock. On and after the first reset date of the Series A Preferred Stock, the dividend rate on the Series A Preferred Stock for each subsequent five-year period (each, a Reset Period) will be adjusted based upon the applicable Treasury rate, plus a spread of 6.93% per annum; provided that the applicable Treasury rate for each Reset Period will not be lower than 1.07%. On and after the first reset date of the Series B Preferred Stock, the dividend rate on the Series B Preferred Stock for each Reset Period will be adjusted based upon the applicable Treasury rate, plus a spread of 5.74% per annum; provided that the applicable Treasury rate for each Reset Period will not be lower than 1.26%. On and after the first reset date of the Series C Preferred Stock, the dividend rate on the Series C Preferred Stock for each Reset Period will be adjusted based upon the applicable Treasury rate, plus a spread of 5.045% per annum; provided that the applicable Treasury rate for each Reset Period will not be lower than 3.830%. In the event that the Company does not exercise its option to redeem all the shares of Preferred Stock within 120 days after the first date on which a Change of Control Trigger Event (as defined in the Certificate of Designation) occurs, the then-applicable dividend rate for the Preferred Stock will be increased by 5.00%.

Item 1B.UNRESOLVED STAFF COMMENTS

None.

VISTRA CORP.

Item 1C.CYBERSECURITY

The Company has a cybersecurity and incident response program designed to assess, identify, and manage material risks from cybersecurity threats, including matters related to the cybersecurity of the Company's critical infrastructure, data, or information technology systems and the Company's actions to prepare for, identify, assess, respond, mitigate and remediate material cyber, information security, or technology risks (collectively referred to as Information Security). This program includes:

•operating a Cyber Security Operations Center;

•raising employee awareness through annual general and job-specific cybersecurity trainings and employee phishing simulations;

•maintaining defined cyber incident response plans;

•enhancing security measures to protect our systems and data;

•evolving monitoring capabilities to improve early detection and rapid response to potential cyber threats; and

•mitigating remote network risk to our internal systems, assets, or data.

Cybersecurity represents an important component of the Company's overall approach to enterprise risk management and is integrated into the risk management process and ongoing assessment. In addition to an internal security program, we strive to stay ahead of the threat landscape by actively monitoring and conducting due diligence on key third-party vendors' Information Security programs and risks. This includes qualitative assessments to gain a deeper understanding of their security posture and potential vulnerabilities. We make strategic investments in our perimeter and internal defenses, cyber security operations center, and regulatory compliance activities with the advice of consultants and third parties. Moreover, to minimize risk, we maintain an insurance policy that provides coverage for matters relating to Information Security.

Vistra's Chief Information Officer (CIO) ensures Information Security is built into the Company's larger technology strategy and oversees our Chief Information Security Officer (CISO). Our CISO and his Information Security team are responsible for leading the enterprise-wide information security strategy, policy, standards, architecture, and processes. Additionally, our Cyber Incident Response Teams under the CISO are responsible for monitoring and analyzing the Company's cybersecurity posture in partnership with Risk and Legal.

The CIO and CISO collaborate with our internal audit department and external consultants to review information technology-related risks (based upon the National Institute of Standards and Technology (NIST) Cybersecurity Framework) as part of the overall Vistra cyber risk management process. Through these processes, the CIO and CISO are informed about and monitor the prevention, detection, mitigation, and remediation of cybersecurity threats.

We also participate in industry groups and with regulators to gain additional knowledge, including, but not limited to, the Federal Bureau of Investigation, U.S. Cybersecurity and Infrastructure Security Agency, U.S. Department of Homeland Security, Electricity Information Sharing and Analysis Center, U.S. Cyber Emergency Response Team, the NRC and NERC. We apply the knowledge gained through industry partnerships, government organizations, external cyber risk platforms, and program maturity assessments to improve our processes to detect and mitigate cyber threats.

As of the date of this report, we have not identified any impacts from cybersecurity threats, including those from any previous cybersecurity incidents, that have materially affected our results of operation or financial condition. However, despite our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced undetected cybersecurity incidents. For additional information on risks from cybersecurity threats, see Item 1A. Risk Factors.

The Sustainability and Risk Committee of the Board has been delegated oversight responsibility of Vistra's Information Security. Vistra periodically engages third-party advisors to provide cybersecurity oversight and tabletop training to the full Board to further our commitment to responsible oversight of cybersecurity risk management. At least quarterly, our CIO reports to the Sustainability and Risk Committee of the Board on our Information Security program, including cybersecurity risks and threats (including the emerging threat landscape), an assessment of our Information Security program, and the status of projects to strengthen our Information Security program. In furtherance of our commitment to responsible oversight of cybersecurity risk management, in 2023, the Board appointed a director who brings extensive cybersecurity expertise to the Board.

VISTRA CORP.

Our CIO serves as head of Vistra's Technology Services and is responsible for ensuring the reliability, security, and continued development of the Company's technology platforms and delivering new solutions to support the business. The CIO has served in various senior information technology roles in public companies for over 30 years, including Keurig Dr. Pepper Inc., General Motors, Pfizer, and Electronic Data Systems.

Our CISO has over 24 years of information technology experience. He has held technology positions across various areas, including infrastructure management, application management, architecture, operations, and cybersecurity, and brings expertise from Farmers Insurance and Zurich Insurance.

Item 2.PROPERTIES

The following table presents our asset fleet as of December 31, 2025 by segment. All of our facilities are 100% (fee simple) owned.

Facility

Location

ISO/RTO

Technology

Primary Fuel

Net Capacity (MW) (a)

Texas Segment

Ennis

Ennis, TX

ERCOT

CCGT

Natural Gas

366

Forney

Forney, TX

ERCOT

CCGT

Natural Gas

1,912

Hays

San Marcos, TX

ERCOT

CCGT

Natural Gas

1,122

Lamar

Paris, TX

ERCOT

CCGT

Natural Gas

1,180

Midlothian

Midlothian, TX

ERCOT

CCGT

Natural Gas

1,596

Odessa

Odessa, TX

ERCOT

CCGT

Natural Gas

1,180

Wise

Poolville, TX

ERCOT

CCGT

Natural Gas

787

DeCordova

Granbury, TX

ERCOT

Natural Gas

362

Morgan Creek

Colorado City, TX

ERCOT

Natural Gas

446

Permian Basin

Monahans, TX

ERCOT

Natural Gas

404

Graham

Graham, TX

ERCOT

Natural Gas

630

Lake Hubbard

Dallas, TX

ERCOT

Natural Gas

921

Stryker Creek

Rusk, TX

ERCOT

Natural Gas

685

Trinidad

Trinidad, TX

ERCOT

Natural Gas

244

Coleto Creek

Goliad, TX

ERCOT

Coal

650

Martin Lake

Tatum, TX

ERCOT

Coal

2,455

Oak Grove

Franklin, TX

ERCOT

Coal

1,710

Comanche Peak

Glen Rose, TX

ERCOT

Nuclear

Uranium

2,400

Brightside

Live Oak County, TX

ERCOT

Solar

Renewable

Emerald Grove

Crane County, TX

ERCOT

Solar

Renewable

108

Oak Hill

Rusk County, TX

ERCOT

Solar

Renewable

200

Upton 2

Upton County, TX

ERCOT

Solar/Battery

Renewable

190

DeCordova

Granbury, TX

ERCOT

Battery

Renewable

260

Total Texas Segment

19,858

East Segment

Beaver Falls

Beaver Falls, NY

NYISO

CCGT

Natural Gas

108

Independence

Oswego, NY

NYISO

CCGT

Natural Gas

1,212

Syracuse

Solvay, NY

NYISO

CCGT

Natural Gas

103

Bellingham

Bellingham, MA

ISO-NE

CCGT

Natural Gas

566

Blackstone

Blackstone, MA

ISO-NE

CCGT

Natural Gas

544

Casco Bay

Veazie, ME

ISO-NE

CCGT

Natural Gas

543

Lake Road

Dayville, CT

ISO-NE

CCGT

Natural Gas

827

Manchester

Providence, RI

ISO-NE

CCGT

Natural Gas

510

Masspower

Indian Orchard, MA

ISO-NE

CCGT

Natural Gas

281

Milford

Milford, CT

ISO-NE

CCGT

Natural Gas

600

VISTRA CORP.

Facility

Location

ISO/RTO

Technology

Primary Fuel

Net Capacity (MW) (a)

Baldwin

Baldwin, IL

MISO

Solar/Battery

Renewable

Coffeen

Coffeen, IL

MISO

Solar/Battery

Renewable

Baldwin

Baldwin, IL

MISO

Coal

1,185

Newton

Newton, IL

MISO

Coal

615

Kincaid

Kincaid, IL

PJM

Coal

1,108

Miami Fort 7 & 8

North Bend, OH

PJM

Coal

1,020

Fairless

Fairless Hills, PA

PJM

CCGT

Natural Gas

1,320

Fayette

Masontown, PA

PJM

CCGT

Natural Gas

726

Garrison

Dover, DE

PJM

CCGT

Natural Gas

309

Hanging Rock

Ironton, OH

PJM

CCGT

Natural Gas

1,430

Hopewell

Hopewell, VA

PJM

CCGT

Natural Gas

370

Kendall

Minooka, IL

PJM

CCGT

Natural Gas

1,288

Liberty

Eddystone, PA

PJM

CCGT

Natural Gas

607

Ontelaunee

Reading, PA

PJM

CCGT

Natural Gas

600

Sayreville

Sayreville, NJ

PJM

CCGT

Natural Gas

349

Washington

Beverly, OH

PJM

CCGT

Natural Gas

711

Calumet

Chicago, IL

PJM

Natural Gas

380

Dicks Creek

Monroe, OH

PJM

Natural Gas

155

Hazleton

Pardeesville, PA

PJM

Natural Gas

158

Pleasants

Saint Marys, WV

PJM

Natural Gas

388

Miami Fort (CT)

North Bend, OH

PJM

Fuel Oil

Beaver Valley 1 & 2

Shippingport, PA

PJM

Nuclear

Uranium

1,872

Perry

Perry, OH

PJM

Nuclear

Uranium

1,268

Davis-Besse

Oak Harbor, OH

PJM

Nuclear

Uranium

908

Total East Segment

22,254

West Segment

Moss Landing 1 & 2

Moss Landing, CA

CAISO

CCGT

Natural Gas

1,020

Moss Landing (b)

Moss Landing, CA

CAISO

Battery

Renewable

350

Oakland

Oakland, CA

CAISO

Fuel Oil

110

Greenleaf

Yuba City, CA

CAISO

Natural Gas

Total West Segment

1,529

Total capacity

43,641

___________

(a)Approximate net generation capacity. Actual net generation capacity may vary based on a number of factors, including ambient temperature. Capacity based on winter rating. We have not included units that have been retired or are out of operation. See Note 7 to the Financial Statements for additional information.

(b)Net capacity represents the Moss Landing 350 MW battery facility and excludes the Moss Landing 100 and 300 MW battery facilities as they will not return to service. See Note 8 to the Financial Statements for additional information.

Our wholesale commodity risk management group also procures renewable energy credits from renewable generation in ERCOT and PJM to support our electricity sales to wholesale and retail customers to satisfy the increasing demand for renewable resources from such customers. As of December 31, 2025, Vistra had long-term agreements to procure renewable energy credits from approximately 950 MW of renewable generation. These renewable generation sources deliver electricity when conditions make them available, and, when on-line, they generally compete with baseload units. Because they cannot be relied upon to meet demand continuously due to their dependence on weather and time of day, these generation sources are categorized as non-dispatchable and create the need for intermediate/load-following resources to respond to changes in their output.

VISTRA CORP.

Item 3.LEGAL PROCEEDINGS

See Note 18 to the Financial Statements for additional information.

Item 4.MINE SAFETY DISCLOSURES

Vistra currently owns and operates, or is in the process of reclaiming, 12 surface lignite coal mines in Texas to provide fuel for its electricity generation facilities. Vistra also owns or leases, and is in the process of reclaiming, two waste-to-energy surface facilities in Pennsylvania. These mining operations are regulated by the MSHA under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), along with other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects U.S. mines, including Vistra's mines, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders, and proposed assessments are provided in Exhibit 95.1 to this annual report on Form 10-K.

VISTRA CORP.

PART II

Item 5.MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Vistra's common stock is listed and traded on the NYSE and the NYSE Texas under the symbol "VST". Vistra's authorized capital stock consists of 1,800,000,000 shares of common stock with a par value of $0.01 per share.

As of February 18, 2026, there were 378 stockholders of record.

The Board has authority to declare dividends to the holders of our common stock. The Board intends to continue the payment of dividends to the holders of the Company's common stock in the future. The declaration and payment of future dividends, however, will be at the discretion of the Board and will depend on numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and contractual limitations.

Stock Performance Graph

The performance graph below compares Vistra's cumulative total return on common stock during the five-year period from December 31, 2020 through December 31, 2025 with the cumulative total returns of the S&P 500 Stock Index (S&P 500) and the S&P Utility Index (S&P Utilities). The graph below compares the return in each period assuming that $100 was invested at December 31, 2020 in Vistra's common stock, the S&P 500 and the S&P Utilities, and that all dividends were reinvested.


	December 31,
	2020		2021		2022		2023		2024		2025
Vistra Corp.	$	100.00	$	119.55	$	125.62	$	224.45	$	774.87	$	911.64
S&P 500	$	100.00	$	128.68	$	105.36	$	133.03	$	166.28	$	195.98
S&P Utilities	$	100.00	$	117.67	$	119.51	$	111.05	$	137.07	$	159.06

VISTRA CORP.

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

Purchases of Equity Securities by the Issuer

The following table provides information about our repurchase of common stock, during the three months ended December 31, 2025.


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)
October 1 - October 31, 2025	371,820	$	199.20	371,820	$	2,174
November 1 - November 30, 2025	509,144	$	177.68	509,144	$	2,084
December 1 - December 31, 2025	500,181	$	167.91	500,181	$	2,000
For the quarter ended December 31, 2025	1,381,145	$	179.94	1,381,145	$	2,000

In October 2021, the Board authorized a share repurchase program (Share Repurchase Program). Under this program, shares of the Company's common stock may be repurchased in open market transactions, privately negotiated transactions, or other means in accordance with federal securities laws. The timing, number, and value of shares repurchased will be determined at our discretion, considering factors such as capital allocation priorities, stock market price, general market and economic conditions, legal requirements, and compliance with debt agreements and preferred stock certificates of designation. We expect to complete repurchases under the Share Repurchase Program by the end of 2027.


Board Authorization Dates	Amount Authorized for Share Repurchases
	(in billions)
October 2021	$	2.00
August 2022	1.25
March 2023	1.00
February 2024	1.50
October 2024	1.00
October 2025	1.00
Cumulative authorization at December 31, 2025	$	7.75

See Note 19 to the Financial Statements for additional information.

Item 6.[RESERVED]

Not applicable.

Item 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read together with the consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data. See Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations in our 202 4 Form 10-K for a discussion of our financial condition and results of operations for the year ended December 31, 2023 and for the year ended December 31, 2024 compared to the year ended December 31, 2023, which is incorporated here by reference.

VISTRA CORP.

Key Financial Results

The following are financial and operating highlights we achieved in the execution of our four strategic priorities:

Long-term, attractive earnings profile through the integrated business model.

•We continued to execute our integrated business model, delivering strong operational and financial performance while responding effectively to market opportunities. Our ability to combine a diversified and dependable generation fleet with a scaled retail platform and disciplined wholesale risk management capabilities remains a core competitive advantage and supports more stable and predictable cash flows across commodity price cycles.

•Long-term contracts entered in 2025 underwrite higher base profitability in the future.

◦In September 2025, we announced that we had entered into a 20-year power purchase agreement (PPA) (with options to extend for up to an additional 20 years) with Amazon Web Services (AWS) to supply 1,200 MW of carbon-free power from our Comanche Peak Nuclear Power Plant. We anticipate power delivery to begin in the fourth quarter of 2027 and ramp to full capacity by 2032.

◦In January 2026, we announced that we had entered into 20-year PPAs with Meta Platforms, Inc. (Meta) to supply 2,609 MW of carbon-free power and capacity from our PJM nuclear power plants, including 2,176 MW of operating energy and capacity and 433 of uprate energy and capacity to be constructed. We anticipate commencing delivery on a portion of the operating energy and capacity in late 2026 and full delivery by year end 2027. We anticipate commencing delivery on a portion of the uprate energy and capacity by 2031 and full delivery by year end 2034.

Disciplined capital allocation.

•Executed disciplined capital allocation through targeted natural gas expansion, including the development of an 860 MW facility in West Texas and the acquisition of 2,600 MW of natural gas generation capacity from Lotus.

•In December 2025, we executed definitive agreements to acquire Cogentrix Energy, consisting of 10 natural gas generation facilities totaling approximately 5,500 MW of capacity. The transaction is expected to close in mid-to-late 2026.

•During the year ended December 31, 2025, we paid dividends to common stockholders totaling $306 million.

•In October 2025, the Board authorized an incremental amount of $1.0 billion under our stock repurchase program established in October 2021. During the year ended December 31, 2025, we repurchased 6.6 million shares for approximately $1.0 billion under the program. Through February 18, 2026, total shares repurchased under the program totaled 167 million shares for $5.9 billion, and we have $1.8 billion available for additional repurchases under the program.

•In December 2025, S&P raised its issuer credit rating on Vistra to investment grade from BB+ to BBB-.

Maintaining a resilient balance sheet.

•We further diversified our sources of liquidity and improved associated borrowing costs and credit terms through a number of enhancements and amendments to our facilities throughout the year, including (i) extending the maturity of the Commodity-Linked Facility to September 2026, (ii) increasing the commitment cap under the alternative letter of credit facility from $500 million to $800 million, and (iii) expanding and extending the Receivables Facility purchase limit by $100 million and extended the term to July 2026.

•In October 2025, we issued $750 million of 4.300% senior secured notes due 2028, $500 million of 4.600% senior secured notes due 2030, and $750 million of 5.250% senior secured notes due 2035. The net proceeds from these issuances were used to refinance senior unsecured debt maturities in September 2026 and for general corporate purposes, including to fund a portion of the Lotus Acquisition.

Strategic energy transition focused on the reliability, affordability, and sustainability of electric grid.

•Planned uprates at the Company's operating Perry Nuclear Power Plant (Perry), Davis-Besse Nuclear Power Plant (Davis-Besse), and Beaver Valley Nuclear Power Plant (Beaver Valley) would add 433 MW of incremental carbon-free nuclear energy and capacity to the PJM region commencing delivery on a portion of the uprate energy and capacity by 2031 and full delivery of the uprate energy and capacity by year end 2034.

•We reached commercial operations at the Oak Hill solar facility in Texas totaling 200 MW of capacity and continued development and construction activities on additional facilities at retired or to-be-retired plant sites in Illinois.

VISTRA CORP.

•We announced plans to repower the Coleto Creek and Miami Fort coal generation facilities as natural gas-fueled facilities upon their retirement no later than 2027 and the middle of 2028, respectively.

Business Environment and Outlook

Electricity Demand

Electricity demand drivers including the rise of large scale data centers, the electrification of oil field operations, and electric vehicle load building are contributing to a projected fast paced load growth in the regions we serve. Our integrated retail electricity and power generation operations allows us to quickly respond to electricity demand changes. To support growing demand from large‑scale electricity consumers, we continue to engage in discussions with various counterparties regarding the potential long-term sale of power from our generation facilities, and we are progressing a series of development initiatives across our generation portfolio, including nuclear uprates and other capacity expansions.

Supply Chain Constraints

Our industry continues to face ongoing supply chain constraints and labor shortages, which have reduced the availability of essential equipment and supplies for constructing new generation facilities, increased the lead times for procuring materials, and raised labor costs associated with maintaining our natural gas, nuclear, and coal fleet.

We are proactively managing these constraints by continuously re-evaluating the business cases and timing of our planned development projects. This has led to the deferral or abandonment of some planned capital expenditures for our solar and battery projects and could impact the economic feasibility of additional projects in our new generation development pipeline. We are engaging with suppliers to secure key materials needed to maintain our existing generation facilities before future planned outages.

Russia/Ukraine Conflict

We are closely monitoring developments in the Russia and Ukraine conflict, specifically sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. The Prohibiting Russian Uranium Imports Act (PRUI Act), which was signed into law on August 11, 2024, prohibits importation of Russian uranium; however, the DOE can issue waivers (subject to decreasing annual caps) until December 31, 2027 if there is no alternate source of low-enriched uranium available to keep U.S. nuclear reactors operating or is in the national interest. Additionally, passage of the PRUI Act enabled the allocation of $2.72 billion in federal funding to ramp up production of domestic uranium fuel. On November 15, 2024, the Russian Federation temporarily suspended shipments of uranium to the U.S., stating that they would grant future export licenses on a case-by-case basis.

Our 2026 refueling plans have not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel impacting our refueling schedules. All nuclear fuel requirements for 2026 are either in inventory or are onshore. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance. We have nuclear fuel contracted to support all our refueling needs through 2030 without any additional Russian deliveries. We continue to take affirmative action by building strategic inventory and deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facilities through potential Russian supply disruption.

Noteworthy Developments

PJM Nuclear Power Purchase Agreements and Uprates

In January 2026, Vistra announced it had entered into 20-year PPAs with Meta, pursuant to which the Company has agreed to supply Meta with a total of 2,609 MW of carbon-free power and capacity from the Company's PJM nuclear power plants as follows:

•1,268 MW of energy and capacity from Perry and 908 MW of energy and capacity from Davis-Besse; and

•213 MW of uprate energy and capacity from Perry, 80 MW of uprate energy and capacity from Davis-Besse, and 140 MW of uprate energy and capacity from Beaver Valley.

VISTRA CORP.

Under the terms of the PPAs, the Company anticipates commencing delivery on a portion of the operating energy and capacity in late 2026 and full delivery of the operating energy and capacity by year end 2027. Additionally, the Company anticipates commencing delivery on a portion of the uprate energy and capacity by 2031 and full delivery of the uprate energy and capacity by year end 2034. To achieve the uprates, the Company expects to incur capital expenditures commencing in 2026 and extending through 2034, with less than 20% of the aggregate spend projected to occur by year end 2028. The timing and amount of our planned uprate expenditures will depend on a range of factors, including regulatory approvals, engineering evaluations and capital allocation decisions.

Cogentrix Transaction

On December 31, 2025, Vistra executed definitive agreements to acquire Cogentrix Energy which consists of 10 modern natural gas generation facilities totaling approximately 5,500 MW of capacity (Cogentrix Transaction). The facilities include three combined cycle gas turbine facilities and two combustion turbine facilities located across PJM, four combined cycle gas turbine facilities in ISO-NE, and one cogeneration facility in ERCOT.

Aggregate consideration at closing will consist of approximately (i) $2.3 billion in cash, net of adjustments for the assumption of an estimated $1.5 billion of outstanding indebtedness of Cogentrix as of the closing date, and (ii) 5,000,000 shares of Vistra common stock, par value $0.01, to be issued to the seller, at a mutually agreed-upon value of $185 per share.

Consummation of the Cogentrix Transaction is subject to customary closing conditions, including receipt of all requisite regulatory approvals, including approvals of FERC and the expiration or termination of all applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The Cogentrix Transaction is expected to close in mid-to-late 2026.

Lotus Acquisition

On October 22, 2025, pursuant to a purchase and sale agreement dated May 15, 2025, Vistra Operations acquired 100% of the membership interests of certain subsidiaries of Lotus (Lotus Acquisition). The Lotus Acquisition resulted in the addition of seven natural gas generation facilities totaling 2,600 MW in Delaware and Pennsylvania (PJM), Rhode Island (ISO-NE), New York (NYISO), and California (CAISO), further geographically diversifying Vistra's natural gas fleet.

The aggregate purchase price consisted of a base purchase price of $1.9 billion, subject to certain customary adjustments, including the acquired companies' working capital, cash, indebtedness, and certain other adjustments. Vistra Operations funded the Lotus Acquisition with a combination of cash and the assumption of the acquired companies' indebtedness which consisted of a senior secured credit facility, including an existing term loan with approximately $800 million principal outstanding, which reduced the cash consideration payable at closing. Cash consideration payable at closing, excluding adjustments for the acquired companies' working capital, cash, and certain other adjustments, was $1.1 billion. See Note 2 to the Financial Statements for additional information.

Comanche Peak Power Purchase Agreement

In September 2025, Vistra announced that it had entered into a 20-year PPA (with options to extend for up to an additional 20 years) with AWS, pursuant to which we have agreed to supply to AWS 1,200 MW of carbon-free power from the Comanche Peak Nuclear Power Plant. Vistra anticipates power delivery to begin in the fourth quarter of 2027 and ramp to full capacity by 2032.

Nuclear Plant License Renewal

In July 2025, our application for license renewal at our Perry Nuclear Plant was approved by the NRC. The license now extends through 2046.

VISTRA CORP.

OBBBA and CAMT

In July 2025, the legislation known as the OBBBA was signed into law and we have accounted for the effects in our consolidated financial statements. Key changes include the immediate expensing of domestic research and development costs, the reinstatement of 100% bonus depreciation, and increases in the limitation of interest deductibility. Certain provisions of the OBBBA will change the timing of cash tax payments in the current fiscal year and future year periods, however the legislation did not have a material impact on our consolidated financial statements. We do not expect Vistra to be subject to the corporate alternative minimum tax (CAMT) in the 2025 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the CAMT and forecasted OBBBA impacts into account when forecasting cash taxes.

Moss Landing 300 Incident

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site (the Moss Landing Incident) that resulted in ceasing operations at all facilities at the Moss Landing complex until the fire was contained. No injuries occurred due to the fire or the Company's response. The Moss Landing complex includes two other battery facilities and a gas plant. The gas plant returned to service in February 2025. The Moss Landing 350 MW battery facility has a net book value of approximately $320 million as of December 31, 2025. We are working towards a return to service in mid-2026, but we will continue to evaluate our restart plans following completion of our investigation into the cause of the fire. After further consideration, management determined it would not return the Moss Landing 100 MW battery to service.

As a result of the damage caused by the Moss Landing Incident, during the three months ended March 31, 2025, we wrote-off the net book value of Moss Landing 300 of approximately $400 million to depreciation expense and moved the asset to the Asset Closure segment as we have no plans to return the Moss Landing 300 facility to operations. See Notes 7 and 21 to the Financial Statements for additional information.

As a result of the decision to not return the Moss Landing 100 MW battery to service, we performed an assessment of the recoverability of the facility's carrying value and, during the three months ended December 31, 2025, we recognized an impairment loss of approximately $155 million and moved the asset to the Asset Closure segment (see Notes 7 and 21 to the Financial Statements for additional information.

In July 2025, we entered into an Administrative Settlement Agreement and Order on Consent (ASAOC) with the EPA related to the Moss Landing 300 site. Under the ASAOC, we are required to perform specific battery removal and remediation activities, including battery removal and disposal, building demolition, and air and water monitoring. We estimate the total cost of these activities to be approximately $110 million. We have incurred expenses of approximately $49 million on ASAOC activities through December 31, 2025. As of December 31, 2025, our accrual for estimated future costs for the ASAOC activities is approximately $61 million, which is reflected in other current liabilities in the consolidated balance sheets. This estimate assumes the ASAOC activities will be completed by the end of 2026. Aside from battery removal and disposal, our estimate does not reflect costs associated with removal of other hazardous waste that could be identified as the demolition progresses as we are unable to estimate such costs until sampling of waste material is complete. We will account for any adjustments to the accrual as a change in estimate in the period new information becomes available.

Additional impacts from the Moss Landing Incident include loss of revenue from the facilities being offline and may include litigation costs, other negotiated settlements of contracts with counterparties, and additional non-cash impairment losses. We are currently unable to estimate the full impact the Moss Landing Incident will have on us as our estimate will evolve as demolition progresses. See Note 18 to the Financial Statements for additional information.

We have filed insurance claims against applicable insurance policies with combined business interruption and property loss limits of $500 million, net of deductibles, of which approximately $500 million has been collected through February 2026. See Note 8 to the Financial Statements for additional information. While we expect future revenues in the West segment to decrease relative to 2024 revenues with the Moss Landing 300 and 100 MW battery facilities not returning to service, given the uncertainty in the timing of the restart of the Moss Landing 350 MW battery facility and additional expenses that could be incurred related to the Moss Landing Incident, we cannot predict the full impact this event will have on our 2026 financial statements.

VISTRA CORP.

Martin Lake Unit 1 Incident

On November 27, 2024, we experienced a fire at Unit 1 of our Martin Lake facility in ERCOT (the Martin Lake Incident), an 815 MW unit. We wrote-off the unit's net book value of less than $1 million to depreciation expense in December 2024. The unit returned to service in February 2026. We estimate total cash capital expenditures required to restore the unit to service was approximately $384 million, of which approximately $271 million in cash capital expenditures have been incurred as of December 31, 2025.

We expect to recover a majority of the expenditures associated with the Martin Lake Incident through property damage insurance and to receive additional business interruption proceeds. See Note 8 to the Financial Statements for additional information. Given uncertainty in timing of remaining insurance recoveries, we cannot predict the full impacts this event will have on our 2026 financial statements.

Acquisition of Noncontrolling Interest

On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (as amended, the UPAs) with each of Nuveen and Avenue, pursuant to which Vistra Vision Holdings agreed to purchase each of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision for approximately $3.2 billion in cash (collectively, the Transaction). The Transaction closed on December 31, 2024 (the Closing Date) and Vistra Vision Holdings now owns 100% of the equity interests in Vistra Vision. See Notes 2 and 11 to the Financial Statements for additional information.

Planned Gas-Fueled Dispatchable Power in ERCOT

In May 2024, we announced our intention to add up to 2,000 MW of dispatchable, natural gas-fueled electricity capacity in west, central, and north Texas consisting of the following projects:

•Building up to 860 MW of advanced simple-cycle peaking plants to be located in west Texas to support the increasing power needs of the region, including the state's oil and gas industry.

•Repowering the coal-fueled Coleto Creek Power Plant near Goliad, Texas, set to retire in 2027 to comply with EPA rules, as a natural-gas fueled plant with up to 600 MW of capacity.

•Completing upgrades at existing natural gas-fueled plants that will add more than 500 MW of summer capacity and 100 MW of winter capacity.

In July 2024, we filed applications with the PUCT under the Texas Energy Fund loan program seeking financing for the 860 MW of new advanced simple-cycle peaking plants referenced above. Both projects were selected for due diligence as part of the Texas Energy Fund loan program. An invitation to due diligence does not mean an applicant is awarded a loan. Due diligence is progressing and we are in the final stages.

In September 2025, we announced we will move forward with construction of the 860 MW peaking plants discussed above. Early development work is underway, and we anticipate the units will be online in 2028.

Merger with Energy Harbor

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023, (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen and Avenue exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively, Energy Harbor Merger). The Energy Harbor Merger combined Energy Harbor's and Vistra's nuclear and retail businesses and certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free technologies (dispatchable and renewables/storage) and the retail business. The cash consideration for Energy Harbor Merger was funded by Vistra Operations using a combination of cash on hand and borrowings under the Commodity-Linked Facility, the Receivables Facility and the Repurchase Facility. See Note 2 to the Financial Statements for additional information.

VISTRA CORP.

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC, new technology-neutral ITCs and PTCs that apply to various different clean energy technologies, and a first-time stand-alone battery storage ITC. The IRA also implements a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. The section 45U nuclear PTC is available to existing nuclear facilities from 2024 through 2032 and provides a federal tax credit of up to $15 per MWh, subject to phase out when annual gross receipts are between $25.00 per MWh and 43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively (each subject to annual inflation adjustments). The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to ASC 832, Government Grants as amended by Accounting Standards Update 2025-10 (ASC 832). As discussed in Note 5, we recognized transferable nuclear PTC revenues of $220 million and $545 million in the years ended December 31, 2025 and 2024, respectively. U.S. Treasury regulations are expected to further define the scope of the legislation in many important respects, including interpretive guidance on the definition of gross receipts for the nuclear PTC. Any interpretive guidance on the definition of gross receipts that differs from the interpretation used in our estimates could result in a material change to PTC revenues recorded in 2024 and 2025 and would be reflected as a change in estimate in the period in which the guidance is received.

Factors Affecting Our Financial Condition and Results of Operations

Commodity Prices

The price of electricity has a significant impact on our operating revenues and purchased power costs. Electricity prices are typically set by the cost to fuel a generation facility and the amount of fuel needed to generate one unit of electricity (Heat Rate) from the generation facility. Market Heat Rate is the implied relationship between wholesale electricity prices and the commodity price of the marginal supplier (generally natural gas plants).

Wholesale electricity prices generally move with natural gas prices, except in certain circumstances, such as when ERCOT power prices increase significantly during extreme weather events due to generation scarcity. Because natural gas prices are volatile, the operating costs of our natural gas‑fueled generation facilities can also be volatile. While changes in natural gas prices do not materially affect the cost of generation at our nuclear‑, lignite‑, and coal‑fueled facilities, such changes generally influence electricity prices and, therefore, the operating margins of these facilities. Other factors that may affect electricity prices include fuel costs, regional generation supply, weather conditions, competitive dynamics, emerging technologies, and macroeconomic and regulatory developments.

The wholesale market price of electricity divided by the market price of natural gas represents the Market Heat Rate. Market Heat Rate can be affected by a number of factors, including generation availability, mix of assets and the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. Our Market Heat Rate exposure is impacted by changes in the availability of generation resources, such as additions and retirements of generation facilities, and mix of generation assets. For example, increasing renewable (wind and solar) generation capacity generally depresses Market Heat Rates, particularly during periods when total demand is relatively low. However, increasing penetration of renewable generation capacity may also contribute to greater volatility of wholesale market prices independent of changes in the price of natural gas, given their intermittent nature.

Due to our exposure to variability in natural gas prices and Market Heat Rates, retail sales and hedging activities are critical to our operating results and cash flow stability. Our integrated power generation and retail electricity business provides flexibility to hedge our generation position by utilizing retail markets as an effective sales channel. As we entered the 2025 and 2024 calendar years, substantially all of our expected generation volumes were hedged. This disciplined hedging strategy supports margin protection and contributes to more stable and predictable earnings.

As a result of our hedging strategy, the net income of our segments can be significantly impacted by changes in unrealized gains and losses on commodity derivative instruments which are driven by changes in forward power prices. When power prices increase or decrease compared to what our generation segments have sold forward, the generation segments recognize unrealized losses or gains, respectively. Conversely, the retail segment, which procures power from the generation segments to meet future load obligations, experiences an inverse effect on unrealized mark-to-market valuations compared to the generation segments.

VISTRA CORP.

The below tables summarize the average around the clock settled prices for the periods presented and does not necessarily reflect prices we realized or costs incurred by us.


	Year Ended December 31,					Year Ended December 31,
	2025		2024			2025		2024
Average Power Price ($/MWh):					Average Natural gas price ($/MMBtu):
ERCOT North Hub	$	32.01	$	25.89	NYMEX Henry Hub	$	3.53	$	2.25
ERCOT West Hub	$	32.87	$	27.45	Houston Ship Channel	$	3.01	$	1.87
PJM AEP Dayton Hub	$	45.13	$	30.74	Permian Basin	$	0.62	$	0.08
PJM Northern Illinois Hub	$	36.65	$	25.46	Dominion South	$	2.78	$	1.67
PJM Western Hub	$	50.25	$	33.83	Tetco ELA	$	3.30	$	2.08
MISO Indiana Hub	$	43.73	$	31.36	Chicago Citygate	$	3.25	$	2.12
ISONE Massachusetts Hub	$	67.86	$	41.47	TetcoM3	$	3.69	$	2.07
New York Zone A	$	52.88	$	32.66	Algonquin Citygates	$	6.23	$	3.03
CAISO NP15	$	38.22	$	40.67	PG&E Citygate	$	3.39	$	3.09

Estimated hedging levels for generation volumes in our Texas, East and West segments as of December 31, 2025 were as follows:


	2026		2027
Nuclear/Renewable/Coal Generation:
Texas	100	%	100	%
East	89	%	65	%
Natural Gas Generation:
Texas	92	%	43	%
East	98	%	72	%
West	100	%	42	%

Seasonality

The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results are impacted by extreme or sustained weather conditions and may fluctuate on a seasonal basis. Typically, demand for and the price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme winter weather have made, and may make, such fluctuations more pronounced. The pattern of this fluctuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.

To illustrate the impact of weather variability on our operating results, the following table presents cooling and heating degree days relative to normal levels by segment in 2025 and 2024.


	Year Ended December 31,
	Retail				Texas				East				West
	2025		2024		2025		2024		2025		2024		2025		2024
Weather - percent of normal (a):
Cooling degree days	104	%	112	%	108	%	112	%	94	%	103	%	88	%	90	%
Heating degree days	94	%	78	%	99	%	77	%	104	%	88	%	113	%	119	%

____________

(a)Reflects cooling degree or heating degree days based on Weather Services International (WSI) data. A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base temperature. Retail amounts represent weather data for the Dallas-Fort Worth area.

VISTRA CORP.

Capacity Markets

PJM, NYISO, ISO-NE, MISO and CAISO ensure long-term grid reliability through monthly, semiannual, annual, and multi-year capacity auctions or bilateral transactions where power suppliers commit to making the generation resources available to the ISO as needed for a specific time period. We participate in these capacity market auctions and also enter into bilateral capacity sales, and a portion of our East, and West segment revenues are impacted by the capacity auction results or bilateral contracts. The following information summarizes the auction pricing for zones in which we operate as well as our capacity auction and bilateral capacity sales by planning period. Performance incentive rules increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level.

PJM

Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each planning year:


	2025-2026		2026-2027		2027-2028
	(average price per MW-day)
RTO zone	$	269.92	$	329.17	$	333.44
ComEd zone	269.92		329.17		333.44
MAAC zone	269.92		329.17		333.44
EMAAC zone	269.92		329.17		333.44
ATSI zone	269.92		329.17		333.44
DEOK zone	269.92		329.17		333.44
DOM zone	444.26		329.17		333.44

Our auction and bilateral capacity sales in PJM, net of purchases, aggregated by planning year through planning year 2027-2028, are as follows:


	East Segment
	2025-2026	2026-2027	2027-2028


Capacity sold, net (MW)	11,259		11,527	10,566

NYISO

The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period:


	Winter 2025 - 2026
Price per kW-month	$	2.71

Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through bilateral trades. Our auction and bilateral capacity sales, aggregated by season through winter 2027-2028, are as follows:


	East Segment
	Winter 2025 - 2026	Summer 2026	Winter 2026 - 2027	Summer 2027	Winter 2027 - 2028


Capacity sold (MW)	909	296	174	195	75

ISO-NE

The most recent Forward Capacity Auction results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each planning year:


	2025-2026		2026-2027		2027-2028
Price per kW-month	$	2.59	$	2.59	$	3.58

VISTRA CORP.

We continue to market and pursue longer term multi-year capacity transactions that extend through planning year 2027-2028.


	East Segment
	2025-2026	2026-2027	2027-2028


Capacity sold (MW)	3,453	3,500	3,750

MISO

The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year:


	2025-2026
Price per kW-month	$	6.60

MISO auction and bilateral capacity sales through planning year 2028-2029 are as follows:


	East Segment
	2025-2026	2026-2027	2027-2028	2028-2029


Capacity sold (MW)	1,710	1,418	239	5

CAISO

Our capacity sales as part of the California Public Utilities Commission Resource Adequacy (RA) Program in California, aggregated by calendar year for 2026 through 2029 for Moss Landing, are as follows:


	West Segment
	2026	2027	2028	2029
Bilateral capacity sold (Avg MW)	1,415	1,265	350	350

Results of Operations

The tables and discussion that follows present period‑over‑period changes in our results of operations and highlight the primary drivers of those variances for the periods presented.

In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed (i) with our GAAP results and (ii) the accompanying reconciliations to corresponding GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.

These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition, an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review the consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).

VISTRA CORP.

Consolidated Results of Operations

The following table presents Net income (loss), EBITDA and Adjusted EBITDA:


	Year Ended December 31, 2025
	Retail		Texas		East		West		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	14,340	$	5,353	$	6,174	$	325	$	74	$	(8,528)	$	17,738
Fuel, purchased power costs, and delivery fees	(11,686)		(1,990)		(3,807)		(149)		—		8,531		(9,101)
Operating costs	(168)		(1,050)		(1,381)		(59)		(154)		9		(2,803)
Depreciation and amortization	(94)		(638)		(1,120)		(61)		2		(75)		(1,986)
Selling, general, and administrative expenses	(1,035)		(180)		(235)		(14)		(66)		(184)		(1,714)

Impairment of long-lived assets	—		(68)		(5)		—		(155)		—		(228)
Operating income (loss)	1,357		1,427		(374)		42		(299)		(247)		1,906
Other income, net	—		124		234		5		24		7		394

Interest expense and related charges	(67)		53		50		7		(4)		(1,218)		(1,179)
Impacts of Tax Receivable Agreement	—		—		—		—		—		2		2

Income (loss) before income taxes	1,290		1,604		(90)		54		(279)		(1,456)		1,123
Income tax expense	—		—		(1)		—		—		(178)		(179)
Net income (loss)	$	1,290	$	1,604	$	(91)	$	54	$	(279)	$	(1,634)	$	944
Income tax expense	—		—		1		—		—		178		179
Interest expense and related charges (a)	67		(53)		(50)		(7)		4		1,218		1,179
Depreciation and amortization (b)	94		771		1,474		61		(2)		75		2,473
EBITDA before Adjustments	1,451		2,322		1,334		108		(277)		(163)		4,775
Unrealized net (gain) loss resulting from commodity hedging transactions	148		(479)		1,013		128		(2)		—		808

Purchase accounting impacts	17		1		33		—		—		—		51


Non-cash compensation expenses	—		—		—		—		—		113		113
Transition and merger expenses	6		(1)		3		—		—		67		75
Impairment of long-lived assets	—		68		5		—		155		—		228


Insurance income (c)	—		(120)		—		—		(71)		—		(191)
Decommissioning-related activities (d)	—		15		(127)		1		116		—		5


ERP system implementation expenses	3		3		4		—		1		—		11
Other, net	(3)		25		17		7		4		(87)		(37)
Adjusted EBITDA	$	1,622	$	1,834	$	2,282	$	244	$	(74)	$	(70)	$	5,838

____________

(a)Corporate and Other includes $67 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $133 million and $354 million, respectively, in the Texas and East segments.

(c)Includes involuntary conversion gain recognized from Martin Lake Incident property damage insurance in the Texas segment and revenues from Moss Landing Incident business interruption proceeds in the Asset Closure segment.

(d)Represents net of all NDT (income) loss of the PJM nuclear facilities and all ARO and environmental remediation expenses and other expenses associated with the Moss Landing Incident.

VISTRA CORP.


	Year Ended December 31, 2024
	Retail		Texas		East		West		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	12,797	$	5,394	$	5,661	$	839	$	39	$	(7,506)	$	17,224
Fuel, purchased power costs, and delivery fees	(10,276)		(1,596)		(2,698)		(218)		(6)		7,509		(7,285)
Operating costs	(159)		(996)		(1,103)		(52)		(101)		(3)		(2,414)
Depreciation and amortization	(114)		(581)		(996)		(58)		(28)		(66)		(1,843)
Selling, general, and administrative expenses	(977)		(169)		(148)		(20)		(48)		(239)		(1,601)


Operating income (loss)	1,271		2,052		716		491		(144)		(305)		4,081
Other income, net	(1)		35		177		(6)		17		69		291

Interest expense and related charges	(54)		46		9		1		(4)		(898)		(900)
Impacts of Tax Receivable Agreement	—		—		—		—		—		(5)		(5)

Income (loss) before income taxes	1,216		2,133		902		486		(131)		(1,139)		3,467
Income tax expense	—		—		—		—		—		(655)		(655)
Net income (loss)	$	1,216	$	2,133	$	902	$	486	$	(131)	$	(1,794)	$	2,812
Income tax expense	—		—		—		—		—		655		655
Interest expense and related charges (a)	54		(46)		(9)		(1)		4		898		900
Depreciation and amortization (b)	114		686		1,278		58		28		66		2,230
EBITDA before Adjustments	1,384		2,773		2,171		543		(99)		(175)		6,597
Unrealized net (gain) loss resulting from commodity hedging transactions	52		(790)		(76)		(332)		(9)		—		(1,155)

Purchase accounting impacts	—		1		(12)		—		—		(14)		(25)
Impacts of Tax Receivable Agreement (c)	—		—		—		—		—		(5)		(5)

Non-cash compensation expenses	—		—		—		—		—		100		100
Transition and merger expenses	2		1		22		—		—		111		136



Decommissioning-related activities (d)	—		26

Vistra Corp. 10-K