Companies: 10,575     total market cap: HK$1076.435 T
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Vistra
VST
#424
Rank
HK$435.93 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
HK$1,287
Share price
0.48%
Change (1 day)
53.10%
Change (1 year)
๐Ÿ”‹ Electricity โšก Energy
Categories
  1. Vistra
  2. Annual Reports (10-K)
  3. Financial Year 2025

Vistra - 10-K annual report 2025


Text size:
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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)
Delaware36-4833255
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
6555 Sierra DriveIrving,Texas75039(214)812-4600
(Address of principal executive offices) (Zip Code)(Registrant's telephone number, including area code)

Title of Each ClassTrading 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 shareVSTNew 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 share336,954,256

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
iii
vii
vii
PART I.
1
1
6
7
9
16
16
17
45
46
47
49
49
PART II.
50
51
51
52
53
53
57
60
67
70
73
73
77
77
79
79
80
82
84
86
86
92
97
101
102
103
106
i

107
110
112
113
122
123
128
132
133
138
140
147
150
150
154
154
155
156
PART III.
157
157
157
157
157
PART IV.
Item 15.
158
180
181

ii

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 TexasAmbit Texas, LLC, a wholly owned subsidiary of Vistra
BCOPBCOP Borrower LLC, a subsidiary of Vistra Zero
DynegyDynegy Inc., and/or its subsidiaries, depending on context
Dynegy Energy ServicesDynegy 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 HarborEnergy Harbor Holdings LLC (formerly known as Energy Harbor Corp.), and/or its subsidiaries, depending on context
Homefield EnergyIllinois 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
Luminantsubsidiaries of Vistra engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management
OncorOncor 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
ParentVistra Corp.
Public PowerPublic 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 EnergyTriEagle 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 EnergyTXU 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 & ElectricU.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 BrandsValue 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
VistraVistra Corp., and/or its subsidiaries, depending on context
Vistra IntermediateVistra 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:
CAISOThe California Independent System Operator
iii

ERCOTElectric Reliability Council of Texas, Inc.
ISO-NEISO New England Inc.
MISOMidcontinent Independent System Operator, Inc.
NYISONew York Independent System Operator, Inc.
PJMPJM Interconnection, LLC
Authoritative Organizations:
CFTCU.S. Commodity Futures Trading Commission
DOE
U.S. Department of Energy
EPAU.S. Environmental Protection Agency
FERCU.S. Federal Energy Regulatory Commission
FTCFederal Trade Commission
IEPAIllinois Environmental Protection Agency
IPCBIllinois Pollution Control Board
IRSU.S. Internal Revenue Service
MSHAU.S. Mine Safety and Health Administration
NERCNorth American Electric Reliability Corporation
NRCU.S. Nuclear Regulatory Commission
OSHA
U.S. Occupational Safety and Health Administration
PUCTPublic Utility Commission of Texas
RCTRailroad 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
SECU.S. Securities and Exchange Commission
TCEQTexas Commission on Environmental Quality
Rules and Regulations:
CAAClean Air Act
ERISAEmployee Retirement Income Security Act of 1974
Exchange ActSecurities Exchange Act of 1934, as amended
IRAInflation Reduction Act of 2022
OBBBA
One Big Beautiful Bill Act
Securities ActSecurities 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
AROasset retirement and mining reclamation obligation
BCOP Credit Agreementcredit 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
CCGTcombined cycle natural gas turbine
CCRcoal combustion residuals
CMEChicago Mercantile Exchange
CO2
carbon dioxide
CTcombustion turbine
EBITDAearnings (net income) before interest expense, income taxes, depreciation and amortization
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Effective DateOctober 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
ESSenergy storage system
FitchFitch Ratings Inc. (a credit rating agency)
GAAPgenerally accepted accounting principles
GHGgreenhouse gas
GWhgigawatt-hours
Heat RateHeat Rate is a measure of the efficiency of converting a fuel source to electricity
ISOindependent system operator
ITCinvestment tax credit
kWkilowatt
loaddemand for electricity
LTSAlong-term service agreements for plant maintenance
Market Heat RateMarket 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.
MMBtumillion British thermal units
Moody'sMoody's Investors Service, Inc. (a credit rating agency)
MWmegawatts
MWhmegawatt-hours
NOX
nitrogen oxide
NYMEXthe New York Mercantile Exchange, a commodity derivatives exchange
NYSENew York Stock Exchange
OPEBpostretirement employee benefits other than pensions
PrefCo Preferred Stock Saleas 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
PTCproduction tax credit
REPretail electric provider
RTOregional transmission organization
S&PStandard & Poor's Ratings (a credit rating agency)
Series A Preferred StockVistra'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 StockVistra'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 StockVistra'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&Aselling, general, and administrative
SO2
sulfur dioxide
SOFRSecured Overnight Financing Rate, the average rate at which institutions can borrow U.S. dollars overnight while posting U.S. Treasury Bonds as collateral
STsteam turbine
Tax Matters AgreementTax 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
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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
TWhterawatt-hours
U.S.United States of America
Vistra Operations Commodity-Linked Credit Agreementcredit 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 Agreementcredit 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

vi

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 FuelTechnologyNet Capacity (MW)% of Net Capacity
Natural GasCCGT, CT or ST26,989 62%
CoalST8,743 20%
UraniumNuclear6,448 15%
RenewableSolar/Battery1,274 3%
Fuel OilCT187 —%
Total43,641 100%

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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:
UnitISONet Capacity (MW)Refueling Outage FrequencyLicense Expiration Date
Comanche Peak Unit 1ERCOT1,200 18 Months2050
Comanche Peak Unit 2ERCOT1,200 18 Months2053
Beaver Valley Unit 1PJM939 18 Months2036
Beaver Valley Unit 2PJM933 18 Months2047
PerryPJM1,268 24 Months
2046
Davis-BessePJM908 24 Months2037
Total6,448 

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:
SegmentNet Capacity (MW)% of Net CapacityISO/RTO
Texas19,858 46%ERCOT
East22,254 51%PJM, ISO-NE, MISO, and NYISO
West1,529 3%CAISO
Total43,641 100%

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.

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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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VISTRA CORP.
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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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;
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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.

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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.

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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.

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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.

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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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VISTRA CORP.
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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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
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•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.

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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.
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•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.

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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.

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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.

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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.

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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.

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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.

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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).

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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.

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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.

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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.
FacilityLocationISO/RTOTechnologyPrimary FuelNet Capacity (MW) (a)
Texas Segment
EnnisEnnis, TXERCOTCCGTNatural Gas366 
ForneyForney, TXERCOTCCGTNatural Gas1,912 
HaysSan Marcos, TXERCOTCCGTNatural Gas1,122 
LamarParis, TXERCOTCCGTNatural Gas1,180 
MidlothianMidlothian, TXERCOTCCGTNatural Gas1,596 
OdessaOdessa, TXERCOTCCGTNatural Gas1,180 
WisePoolville, TXERCOTCCGTNatural Gas787 
DeCordovaGranbury, TXERCOTCTNatural Gas362 
Morgan CreekColorado City, TXERCOTCTNatural Gas446 
Permian BasinMonahans, TXERCOTCTNatural Gas404 
GrahamGraham, TXERCOTSTNatural Gas630 
Lake HubbardDallas, TXERCOTSTNatural Gas921 
Stryker CreekRusk, TXERCOTSTNatural Gas685 
TrinidadTrinidad, TXERCOTSTNatural Gas244 
Coleto CreekGoliad, TXERCOTSTCoal650 
Martin LakeTatum, TXERCOTSTCoal2,455 
Oak GroveFranklin, TXERCOTSTCoal1,710 
Comanche Peak
Glen Rose, TXERCOTNuclearUranium2,400 
BrightsideLive Oak County, TXERCOTSolarRenewable50 
Emerald GroveCrane County, TXERCOTSolarRenewable108 
Oak Hill
Rusk County, TX
ERCOT
Solar
Renewable
200 
Upton 2Upton County, TXERCOTSolar/BatteryRenewable190 
DeCordovaGranbury, TXERCOTBatteryRenewable260 
Total Texas Segment19,858 
East Segment
Beaver Falls
Beaver Falls, NY
NYISO
CCGT
Natural Gas
108 
IndependenceOswego, NYNYISOCCGTNatural Gas1,212 
Syracuse
Solvay, NY
NYISO
CCGT
Natural Gas
103 
BellinghamBellingham, MAISO-NECCGTNatural Gas566 
BlackstoneBlackstone, MAISO-NECCGTNatural Gas544 
Casco BayVeazie, MEISO-NECCGTNatural Gas543 
Lake RoadDayville, CTISO-NECCGTNatural Gas827 
Manchester
Providence, RI
ISO-NE
CCGT
Natural Gas
510 
MasspowerIndian Orchard, MAISO-NECCGTNatural Gas281 
MilfordMilford, CTISO-NECCGTNatural Gas600 
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VISTRA CORP.
FacilityLocationISO/RTOTechnologyPrimary FuelNet Capacity (MW) (a)
BaldwinBaldwin, ILMISOSolar/BatteryRenewable70 
CoffeenCoffeen, ILMISOSolar/BatteryRenewable46 
BaldwinBaldwin, ILMISOSTCoal1,185 
NewtonNewton, ILMISOSTCoal615 
KincaidKincaid, ILPJMSTCoal1,108 
Miami Fort 7 & 8North Bend, OHPJMSTCoal1,020 
Fairless
Fairless Hills, PA
PJM
CCGT
Natural Gas
1,320 
FayetteMasontown, PAPJMCCGTNatural Gas726 
Garrison
Dover, DE
PJM
CCGT
Natural Gas
309 
Hanging RockIronton, OHPJMCCGTNatural Gas1,430 
HopewellHopewell, VAPJMCCGTNatural Gas370 
KendallMinooka, ILPJMCCGTNatural Gas1,288 
LibertyEddystone, PAPJMCCGTNatural Gas607 
OntelauneeReading, PAPJMCCGTNatural Gas600 
SayrevilleSayreville, NJPJMCCGTNatural Gas349 
WashingtonBeverly, OHPJMCCGTNatural Gas711 
CalumetChicago, ILPJMCTNatural Gas380 
Dicks CreekMonroe, OHPJMCTNatural Gas155 
Hazleton
Pardeesville, PA
PJM
CT
Natural Gas
158 
PleasantsSaint Marys, WVPJMCTNatural Gas388 
Miami Fort (CT)North Bend, OHPJMCTFuel Oil77 
Beaver Valley 1 & 2Shippingport, PAPJMNuclearUranium1,872 
PerryPerry, OHPJMNuclearUranium1,268 
Davis-BesseOak Harbor, OHPJMNuclearUranium908 
Total East Segment22,254 
West Segment
Moss Landing 1 & 2Moss Landing, CACAISOCCGTNatural Gas1,020 
Moss Landing (b)
Moss Landing, CACAISOBatteryRenewable350 
OaklandOakland, CACAISOCTFuel Oil110 
Greenleaf
Yuba City, CA
CAISO
CT
Natural Gas
49 
Total West Segment1,529 
Total capacity43,641 
___________
(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.

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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.

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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.
1417
December 31,
202020212022202320242025
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 

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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.
PeriodTotal Number of Shares PurchasedAverage Price Paid per ShareTotal Number of Shares Purchased as Part of a Publicly Announced ProgramMaximum 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 20221.25 
March 20231.00 
February 20241.50 
October 20241.00 
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 2024 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.

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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.
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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.

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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.

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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.

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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.

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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.

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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,
2025202420252024
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:
20262027
Nuclear/Renewable/Coal Generation:
Texas100 %100 %
East89 %65 %
Natural Gas Generation:
Texas92 %43 %
East98 %72 %
West100 %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,
RetailTexasEastWest
20252024202520242025202420252024
Weather - percent of normal (a):
Cooling degree days104 %112 %108 %112 %94 %103 %88 %90 %
Heating degree days94 %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.

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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:
2025-20262026-20272027-2028
(average price per MW-day)
RTO zone$269.92 $329.17 $333.44 
ComEd zone269.92 329.17 333.44 
MAAC zone269.92 329.17 333.44 
EMAAC zone269.92 329.17 333.44 
ATSI zone269.92 329.17 333.44 
DEOK zone269.92 329.17 333.44 
DOM zone444.26 329.17 333.44 

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
2025-20262026-20272027-2028
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:
2025-20262026-20272027-2028
Price per kW-month$2.59 $2.59 $3.58 

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VISTRA CORP.
We continue to market and pursue longer term multi-year capacity transactions that extend through planning year 2027-2028.
East Segment
2025-20262026-20272027-2028
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
2025-20262026-20272027-20282028-2029
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
2026202720282029
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).

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VISTRA CORP.
Consolidated Results of Operations

The following table presents Net income (loss), EBITDA and Adjusted EBITDA:
Year Ended December 31, 2025
RetailTexasEastWestAsset
Closure		Eliminations / Corporate and OtherVistra 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 Adjustments1,451 2,322 1,334 108 (277)(163)4,775 
Unrealized net (gain) loss resulting from commodity hedging transactions148 (479)1,013 128 (2)— 808 
Purchase accounting impacts17 1 33 — — — 51 
Non-cash compensation expenses— — — — — 113 113 
Transition and merger expenses6 (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 expenses3 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.

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VISTRA CORP.
Year Ended December 31, 2024
RetailTexasEastWestAsset
Closure		Eliminations / Corporate and OtherVistra 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 Adjustments1,384 2,773 2,171 543 (99)(175)6,597 
Unrealized net (gain) loss resulting from commodity hedging transactions52 (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 expenses2 1 22 — — 111 136 
Decommissioning-related activities (d)— 26 (91)2 — — (63)
ERP system implementation expenses8 7 5 1 2 — 23 
Other, net17 14 (2)11 2 (111)(69)
Adjusted EBITDA$1,463 $2,032 $2,017 $225 $(104)$(94)$5,539 
____________
(a)Corporate and Other includes $53 million of unrealized mark-to-market net gains on interest rate swaps.
(b)Includes nuclear fuel amortization of $105 million and $282 million, respectively, in the Texas and East segments.
(c)Includes $10 million gain recognized on the repurchase of TRA Rights.
(d)Represents net of all NDT (income) loss, ARO accretion expense for operating assets, and ARO remeasurement impacts for operating assets.

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VISTRA CORP.
Net income for the year ended December 31, 2025 compared to the year ended December 31, 2024 decreased by $1.868 billion. Adjusted EBITDA for the year ended December 31, 2025 compared to the year ended December 31, 2024 increased by $299 million. The primary drivers for the decrease in net income and the increase in Adjusted EBITDA include:
Year Ended December 31, 2025 Compared to 2024
(in millions)
Favorable change in realized revenue net of fuel driven primarily by a full year of Energy Harbor results and higher realized energy and capacity prices partially offset by a decrease in nuclear PTC revenue and a decrease in energy revenues due to the Martin Lake Incident
$468 
Higher retail margins driven by strong counts and one-time gains from supply cost management
169 
Favorable change in retail customer consumption primarily due to weather
48 
Increase in plant operating costs due primarily to inclusion of a full year of Energy Harbor results
(267)
Increase in SG&A and other primarily due to inclusion of a full year of Energy Harbor results and higher technology costs
(119)
Change in Adjusted EBITDA$299 
Change in depreciation and amortization, including nuclear fuel amortization, driven primarily by a full year of Energy Harbor assets in East
(243)
Change in unrealized net gain (loss) resulting from commodity hedging transactions
(1,963)
Impairment of long-lived assets
(228)
Increase in insurance income
191 
Decommissioning-related activities
(68)
Other (including interest expense and income tax expense)
144 
Change in Net income$(1,868)

Results of Operations by Segment

The following section presents the results of operations and net income of Vistra's reportable business segments. See Note 21 of the Financial Statements for a discussion of the Company's segments as defined under the accounting standards for segment reporting.

Retail
Year Ended December 31,
20252024
(in millions)
Net income
$1,290 $1,216 
Adjusted EBITDA
$1,622 $1,463 
Retail electricity sales volumes (GWh):
Sales volumes in ERCOT79,16574,295
Sales volumes in Northeast/Midwest59,97459,066
Total retail electricity sales volumes139,139133,361

Retail net income increased due to higher retail margins driven by strong counts and one-time gains from supply cost management and an increase in customer consumption primarily due to weather, partially offset by a $96 million increase in unrealized mark-to-market losses on commodity derivative positions.

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VISTRA CORP.
Texas
Year Ended December 31,
20252024
(in millions)
Net income
$1,604 $2,133 
Adjusted EBITDA
$1,834 $2,032 
Production volumes (GWh):
Natural gas facilities47,75544,595
Lignite and coal facilities22,67323,307
Nuclear facilities20,05919,670
Solar facilities799757
Capacity factors:
CCGT facilities59.1 %58.1 %
Lignite and coal facilities53.8 %59.0 %
Nuclear facilities95.4 %93.3 %

Texas net income decreased primarily due to a $311 million decrease in unrealized mark-to-market gains on commodity derivative positions, a decrease in energy revenues due to the Martin Lake Incident, a $68 million impairment of long-lived assets related to certain development projects, and a $60 million reduction in nuclear PTC revenue, partially offset by higher realized energy prices and $120 million of involuntary conversion gains on property damage insurance from the Martin Lake Incident.

East
Year Ended December 31,
20252024
(in millions)
Net income (loss)
$(91)$902 
Adjusted EBITDA
$2,282 $2,017 
Production volumes (GWh):
Natural gas facilities62,87060,279
Lignite and coal facilities19,50516,938
Nuclear facilities32,20326,540
Solar facilities227—
Capacity factors:
CCGT facilities63.0 %62.0 %
Lignite and coal facilities56.7 %49.1 %
Nuclear facilities90.8 %89.3 %

East net income decreased primarily due to a $1.1 billion increase in unrealized mark-to-market losses on commodity derivative positions and a $264 million reduction in nuclear PTC revenue, partially offset by inclusion of twelve months of Energy Harbor in 2025 compared to ten months in 2024 and higher realized energy and capacity prices.

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VISTRA CORP.
West
Year Ended December 31,
20252024
(in millions)
Net income
$54 $486 
Adjusted EBITDA
$244 $225 
Production volumes (GWh):
Natural gas facilities2,0924,175
Capacity factors:
CCGT facilities23.0 %46.5 %

West net income decreased primarily due to a $460 million increase in unrealized mark-to-market losses on commodity derivative positions.

Asset Closure Segment
Year Ended December 31,
20252024
(in millions)
Net loss
$(279)$(131)

Asset Closure net loss increased primarily due to a $155 million impairment expense for the Moss Landing 100 MW battery facility and costs associated with the Moss Landing Incident, net of insurance receivables, partially offset by business interruption insurance revenue.

Disaggregated Consolidated Statement of Operations Results

Explanations of variations between periods for selected income statement categories are provided below:

Year Ended December 31,
20252024
(in millions)
Operating revenues
$17,738 $17,224 

Operating revenues increased primarily due to an increase in retail revenue rates, an increase in retail customer consumption primarily due to weather, inclusion of a full year of Energy Harbor retail and wholesale revenues for 2025 compared to ten months in 2024, a $312 million increase in retail transmission charges (offset in fuel, purchased power costs, and delivery fees), and business interruption insurance revenue related to the Martin Lake Incident and Moss Landing Incident, partially offset by an increase of $1.8 billion of unrealized mark-to-market losses on commodity derivative positions and a decrease in nuclear PTC revenues.

Year Ended December 31,
20252024
(in millions)
Fuel, purchased power costs, and delivery fees
$(9,101)$(7,285)

Fuel, purchased power costs, and delivery fees increased primarily due to an $1.219 billion increase in realized fuel costs, a $312 million increase in retail transmission charges (offset in operating revenues) and an increase of $184 million in unrealized mark-to-market losses on commodity derivative positions.

65
VISTRA CORP.
Year Ended December 31,
20252024
(in millions)
Operating costs
$(2,803)$(2,414)

Operating costs increased primarily due to the inclusion of a full year of Energy Harbor operating costs for 2025 compared to 10 months in 2024 of $198 million, higher maintenance and outage costs of $62 million, $77 million in operating costs due to the Moss Landing Incident, net of expected insurance recoveries and higher ARO accretion of $18 million.

Year Ended December 31,
20252024
(in millions)
Depreciation and amortization
$(1,986)$(1,843)

Depreciation and amortization increased primarily due to a $50 million increase in depreciation expense due to the inclusion of a full year of Energy Harbor depreciation expense for 2025 compared to 10 months in 2024 and increased capital expenditures in the Texas and East segments.

Year Ended December 31,
20252024
(in millions)
Selling, general, and administrative expenses
$(1,714)$(1,601)

Selling, general, and administrative expenses increased primarily due to the inclusion of a full year of Energy Harbor selling, general, and administrative expenses for 2025 compared to 10 months in 2024 and an increase in technology costs.

Year Ended December 31,
20252024
(in millions)
Other income, net
$394 $291 

Other income, net increased primarily due to higher insurance income primarily due to involuntary conversion gains from Martin Lake Incident insurance proceeds and NDT net income, partially offset by lower interest income.

Year Ended December 31,
20252024
(in millions)
Interest expense and related charges
$(1,179)$(900)

Interest expense and related charges increased due to higher average borrowings and decrease in unrealized mark-to-market gains on interest rate swaps of $120 million.

Year Ended December 31,
20252024
(in millions)
Income tax expense
$(179)$(655)
Effective tax rate
15.9 %18.9 %

Income tax expense decreased due to lower pre-tax book income in 2025 and a lower effective tax rate.

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VISTRA CORP.
Liquidity and Capital Resources

Our primary sources of liquidity and capital consist of (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) available capacity under our credit facilities, and (iv) access to the debt and equity capital markets. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs. Our hedging strategy is designed to preserve cash flow certainty while maintaining appropriate risk tolerances across our generation portfolio. We complement our hedging strategy with long‑term contracted revenues, including power purchase agreements, to lower our overall hedging requirements.

Sources and Uses of Cash
Year Ended December 31,
20252024
Change
(in millions)
Net cash provided by operating activities$4,070 $4,563 $(493)
Net cash used in investing activities$(4,396)$(5,276)$880 
Net cash used in financing activities$(74)$(1,604)$1,530 

Operating Cash Flows

The change in net cash provided by operating activities is primarily due to a $1.611 billion increase in net margin deposits as $769 million in net margin deposits supporting our hedging strategy were posted for the year ended December 31, 2025 as compared to $842 million in net margin deposits returned for the year ended December 31, 2024, partially offset by an increase in cash from nuclear PTC sales of $469 million, realized operating income primarily due to the addition of Energy Harbor, and higher realized energy and capacity prices.

Investing Cash Flows

The change in net cash used in investing activities is primarily due (i) to the purchase of Energy Harbor for $3.1 billion in March 2024 and (ii) $325 million of insurance proceeds received in 2025 for recovery of damaged property, plant, and equipment associated with the Moss Landing and Martin Lake Incidents, partially offset by (i) the Lotus Acquisition for $1.1 billion in October 2025, (ii) $674 million in higher capital expenditures associated with the Martin Lake Incident and development projects, and (iii) $461 million in higher net purchases of environmental allowances in 2025.

Financing Cash Flows

Our significant financing activities during the years ended December 31, 2025 and 2024 are as follows:

•In 2025, we paid (i) $1.744 billion to redeem senior secured and unsecured notes, (ii) $1.028 billion to repurchase common stock, (iii) $803 million to repay debt assumed in the Lotus Acquisition, (iv) $703 million installment payment to Nuveen to purchase the noncontrolling interest in Vistra Vision, and (v) $498 million in dividends to common and preferred shareholders. In 2025, we (i) issued $2.0 billion in senior secured notes, (ii) borrowed $1.8 billion under the Vistra Operations Credit Facilities and the Commodity-Linked Facility, (iii) borrowed $506 million of project-level debt under the BCOP Credit Facility, and (iv) borrowed $475 million under the accounts receivable financing facilities.
•In 2024, we paid (i) $2.247 billion to redeem senior secured notes, (ii) $1.748 billion to purchase the noncontrolling interests in Vistra Vision from Avenue and Nuveen and $180 million in dividends to them, (iii) $1.266 billion to repurchase common stock, and (iv) $478 million in dividends to common and preferred shareholders. In 2024, we (i) issued $2.750 billion in senior secured notes, (ii) borrowed $1.067 billion of project-level debt under the Vistra Zero and BCOP Credit Facility, and (iii) borrowed $750 million under the accounts receivable financing facilities.

67
VISTRA CORP.
Liquidity

The following table summarizes changes in available liquidity for the year ended December 31, 2025:
December 31, 2025December 31, 2024Change
(in millions)
Cash and cash equivalents (a)$785 $1,188 $(403)
Vistra Operations Credit Facilities — Revolving Credit Facility (b)1,996 2,162 (166)
Vistra Operations — Commodity-Linked Facility (c)2 771 (769)
Total available liquidity (d)(e)$2,783 $4,121 $(1,338)
____________
(a)See the consolidated statements of cash flows in the Financial Statements and Cash Flows above for details of the decrease in cash and cash equivalents for the year ended December 31, 2025.
(b)The decrease in availability for the year ended December 31, 2025 was driven by a $380 million increase in cash borrowings, partially offset by a $214 million decrease in letters of credit outstanding under the facility.
(c)As of December 31, 2025 and 2024, the borrowing bases were less than the facility limit of $1.75 billion. As of December 31, 2025, available capacity reflects the borrowing base of $1.422 billion and $1.420 billion in cash borrowings. As of December 31, 2024, available capacity reflects the borrowing base of $771 million and no cash borrowings.
(d)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 11 to the Financial Statements for additional information.
(e)Excludes any additional letters of credit that may be issued under the Secured LOC Facilities or the Alternative LOC Facilities. See Note 11 to the Financial Statements for additional information.

We believe that we will have access to sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months, including the consummation of the Cogentrix Transaction, the maturity of 2026 debt obligations, including the 5.050% Senior Secured Notes due December 2026, and the upcoming payments associated with the acquisition of Nuveen's noncontrolling interest in Vistra Vision discussed in Note 11 to the Financial Statements.

In January 2026, Vistra further increased its available liquidity through the issuance by Vistra Operations of $2.25 billion aggregate principal amount of senior secured notes, consisting of $1.0 billion aggregate principal amount of 4.700% senior secured notes due 2031 and $1.25 billion aggregate principal amount of 5.350% senior secured notes due 2036. Net proceeds will be used to (i) fund a portion of the consideration for the Cogentrix Transaction (see Note 2 to the Financial Statements for additional Information), (ii) for general corporate purposes, including to repay existing indebtedness, and (iii) to pay fees and expenses related to the offering.

Our operational cash flows tend to be seasonal and weighted toward the second half of the year.

Interest Payments

Interest payments on long-term debt, after taking into account interest rate swaps, are expected to total approximately $930 million in 2026, $1.560 billion in 2027-2028, $1.230 billion in 2029-2030 and $995 million thereafter. See Note 11 to the Financial Statements for additional information.

Commodity Purchase and Services Agreements

Our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments, are expected to total approximately $3.630 billion in 2026, $2.990 billion in 2027-2028, $1.730 billion in 2029-2030 and $1.420 billion thereafter. See Notes 12 and 18 to the Financial Statements for additional information.

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Capital Expenditures

Estimated 2026 capital expenditures and nuclear fuel purchases as of December 31, 2025 total approximately $2.587 billion and include:

•$1.087 billion for investments in generation and mining facilities inclusive of LTSA prepayments;
•$300 million for solar and energy storage development;
•$475 million for nuclear fuel purchases
•$900 million for other growth expenditures, and
•$(175) million of nonrecurring items, including insurance proceeds expected to be received for property damage partially offset by capital expenditures for investment technology, corporate, insurance proceeds, and other.

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit, Eligible Assets (see Note 10 to the Financial Statements for additional information) and other forms of credit support to satisfy such collateral posting obligations. See Note 11 to the Financial Statements for additional information.

Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors, including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other business purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.

As of December 31, 2025, we received or posted cash, letters of credit and Eligible Assets for commodity hedging and trading activities as follows:

•$1.577 billion in cash and Eligible Assets has been posted with counterparties as compared to $841 million posted as of December 31, 2024;
•$7 million in cash has been received from counterparties as compared to $49 million received as of December 31, 2024;
•$2.489 billion in letters of credit has been posted with counterparties as compared to $2.560 billion posted as of December 31, 2024; and
•$162 million in letters of credit has been received from counterparties as compared to $131 million received as of December 31, 2024.

See Note 18 to the Financial Statements for information related to collateral posted in accordance with the PUCT and ISO/RTO rules.

Income Tax Payments

In the next 12 months, we expect to make approximately $21 million in federal income tax payments, $66 million in state income tax payments and no material TRA payments, offset by $3 million in federal income tax refunds and $19 million in state tax refunds.

For the year ended December 31, 2025, there were $11 million federal income tax payments, $86 million in state income tax payments, and $1 million in TRA payments.

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VISTRA CORP.
Financial Covenants and Cross-Default Provisions

The Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement, and Secured LOC Facilities each include a financial covenant. The Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement, Secured LOC Facilities, and certain of our other financing arrangements include cross-default provisions that could result in an event of default if there were a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due. See Note 11 to the Financial Statements for additional information.

Guarantees

See Note 18 to the Financial Statements for additional information.

Commitments and Contingencies

See Note 18 to the Financial Statements for additional information.

Critical Accounting Estimates

See Note 1 of the consolidated financial statements for a description of our accounting policies. The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in our application of GAAP.

Business Combinations

Determining fair values of assets acquired and liabilities assumed in the Energy Harbor Merger and Lotus Acquisition requires significant estimates and judgments. We determined fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 2 to the Financial Statements for additional information. The determination of the fair value of property, plant, and equipment contributed and acquired, commodity derivative instruments, and the nuclear decommissioning asset retirement obligations assumed in the Energy Harbor Merger required the most significant level of estimation uncertainty.

The fair value of each power plant acquired in each acquisition and the fair value of the contributed nuclear business in the Energy Harbor Merger was estimated using a combination of the income approach and the market approach. The income approach was based on the discounted cash flow method, incorporating (i) our estimates of forecasted future growth and long-term prices of electricity, capacity, and nuclear fuel, and (ii) financial performance including revenues, gross margins, operating expenses, taxes, working capital, and capital asset requirements. Projected cash flows were then discounted to a present value employing a discount rate that accounts for the estimated market weighted-average cost of capital, along with any risks unique to the subject cash flows. These estimates are subjective in nature and require judgment to interpret market data. The market valuation method utilized prices paid for reasonably similar assets by other purchasers in the relevant market, with adjustments relating to physical differences in the asset as well as their locations.

See Asset Retirement Obligations (ARO) critical accounting estimate for methodology and assumptions used to estimate the nuclear decommissioning ARO acquired in the Energy Harbor Merger. See Derivative Instruments and Mark-to-Market Accounting critical accounting estimate for methodology and assumptions used to estimate the fair value of acquired commodity derivatives.

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of energy-related commodities, as well as other derivative instruments such as options, swaps, futures, and forwards, primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

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Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. Where quoted market prices are not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative instruments valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity (including certain retail contracts), natural gas and coal, (ii) electricity, natural gas and coal options, and (iii) financial transmission rights. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using proprietary modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. Any significant changes to these inputs could result in a material change to the value of the assets or liabilities recorded in the consolidated balance sheets and could result in a material change to the unrealized gains or losses recorded in the consolidated statements of operations.

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections, which generally eliminate the requirement for mark-to-market recognition in net income. Normal purchases and sales (NPNS) are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are accounted for on an accrual basis. Determining whether a contract qualifies for the normal purchase or sale election requires judgment as to whether or not the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements. If it is determined that a transaction designated as a normal purchase or sale no longer meets the scope exception, the related contract would be recorded on the balance sheet at fair value with immediate recognition through earnings.

See Notes 13 and 14 to the Financial Statements for additional information.

Accounting for Income Taxes

Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgments of the timing and probability of recognition of income and deductions by taxing authorities. Further, we assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we would record a valuation allowance against such deferred tax assets for the amount we would not expect to utilize, which would reduce the carrying value of the deferred tax amounts. When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following:

•the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax assets;
•the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward; and
•the amounts and history of income or losses, adjusted for certain non-recurring items.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities.

Income tax returns are regularly subject to examination by applicable tax authorities. In management's opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination.

See Notes 1 and 6 to the Financial Statements for additional information.

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VISTRA CORP.
Asset Retirement Obligations (ARO)

An ARO liability is initially recorded at fair value when it is initially incurred and the amount of the liability can be reasonably estimated. In estimating the ARO liability, we are required to make significant estimates and assumptions. Our ARO liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, and remediation or closure of coal ash basins. On the Merger Date, we recognized ARO liabilities for the Beaver Valley, Perry and Davis-Besse nuclear plants acquired from Energy Harbor.

For the estimates and assumptions of the nuclear generation plant decommissioning, we use unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs and estimates of the timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. We consider the following decommissioning scenarios: (i) DECON, which assumes major decommissioning activities begin shortly after the facility ceases operations, and (ii) SAFSTOR, which assumes the nuclear facility is placed and maintained in a condition during decommissioning that allows the nuclear facility to be safely stored until subsequently decontaminated within 60 years after the facility ceases operations. Decommissioning cost studies are updated for each of our nuclear units at least every five years unless circumstances warrant a more frequent update.

The estimates and assumptions required for the lignite mining land reclamation include estimates such as costs to fill in mining pits and interpretation of the mining permit closure requirements. We estimate the costs to fill in mining pits utilizing a proprietary model to determine the volume of the pit. The estimates and assumptions required for remediation or closure of coal ash basins have been developed for activities such as pond dewatering, surface stabilization, final cover, and post-closure care, including maintenance and groundwater monitoring. We estimate the costs for these activities based on studies of the volume of each pond or landfill. Additionally, changes in coal ash regulation at the state and federal level can significantly impact the amount of AROs we record. See Note 18 to the Financial Statements for additional information.

Our AROs are adjusted on a regular basis to reflect the passage of time and to incorporate revisions to estimates and judgments including, planned plant retirement dates, amounts and timing of future cash expenditures, discount rates, cost escalation factors, market risk premiums, inflation rates, and if applicable, experience with government regulators regarding similar obligations.

See Note 15 to the Financial Statements for additional information.

Impairment of Goodwill and Other Long-Lived Assets

Goodwill and Intangible Assets with Indefinite Useful Lives

Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the 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. Evaluating goodwill and intangible assets with indefinite useful lives involves applying significant assumptions including discount rates, forecasted results for the applicable reporting unit and retail trade name, market multiples, and growth rates. These assumptions are forward looking and could be affected by future economic and market conditions.

Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill and retail trade name intangible asset is more likely than not less than the fair value. If the entity determines the carrying value is not more likely greater than the fair value, no further testing for impairment is required. On the most recent testing date, we performed a qualitative assessment and determined that it was more likely than not that the fair value of our reporting units and retail trade names exceeded their carrying value. Significant qualitative factors were evaluated included reporting unit and trade name financial performance, market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, and interest rates. See Note 9 to the Financial Statements for additional information.

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VISTRA CORP.
Long-Lived Assets

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. Indicators of impairment for our generation facilities include an expectation of continuing long-term declines in natural gas prices and/or Market Heat Rates, an expectation that "more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life, or additional environmental regulations significantly decrease the cash flows expected from the associated assets. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows given the diverse fuel mix and output rates of our generation asset groups. See Note 7 to the Financial Statements for additional information.

After identifying an indicator of impairment, recoverability of long-lived assets is determined by a comparison of the carrying amount of the long-lived asset group to the net cash flows expected to be generated by the asset group. Assumptions used in our estimate of net cash flows of the asset group include, forward natural gas and electricity prices, forward capacity prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices, and forecasted operating costs. The carrying value of such asset groups is determined to be unrecoverable if the projected undiscounted cash flows are less than the carrying value.

If an asset group carrying value is determined to be unrecoverable, fair value will be calculated based on a market participant view and a loss will be recorded for the amount the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows (income approach) and supported by available market valuations, if applicable. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward electricity prices, forward capacity prices, Market Heat Rates, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices, and the discount rate applied to the forecasted cash flows. Any significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived assets.

Nuclear PTC Revenues

Nuclear PTC revenues are accounted for by analogy to ASC 832, Government Grants as amended by Accounting Standards Update (ASU) 2025-10. Nuclear PTC revenues are based on annual gross receipts generated from qualifying nuclear production in the calendar year. Treasury regulations are expected to further provide interpretive guidance on the definition of gross receipts over the next year. Given the lack of guidance to date, we recognized 2024 and 2025 nuclear PTC revenues based on our best estimate and interpretation of gross receipts which includes settled spot energy revenues and capacity revenues (applicable to our PJM nuclear units only) at each nuclear unit and excludes any hedges and ancillary service revenue. Any interpretive guidance on the definition of gross receipts which differs from the interpretation used in our estimate could result in a material change to PTC revenues attributable to 2024 and 2025 and would be reflected as a change in estimate in the period in which the guidance is received.

We have determined that we will meet the prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier, which is reflected in the amount of nuclear PTC revenue recognized in 2024 and 2025.

Changes in Accounting Standards

See Note 1 to the Financial Statements for additional information.

Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In the normal course of business, our financial position is routinely subject to a variety of risks, including market risks associated with (i) changes in commodity prices, (ii) interest rate movements on outstanding debt, and (iii) credit risk, which is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due to us.

Market risks are monitored by our risk management group which operates independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These practices and methodologies measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions. Measurement techniques include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and stress test scenarios. Risk management regularly reports their analysis to the Company's Risk Committee and Executive Committee, and to the Sustainability and Risk Committee of the Board.

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VISTRA CORP.
Commodity Price Risk and Oversight

Our business is subject to the inherent risks of market fluctuations in the price of commodities for energy-related products we market or purchase in futures markets including electricity, natural gas, uranium, coal, environmental credits and other energy commodities in competitive wholesale markets. Factors that influence these market fluctuations are dependent upon many factors outside of our control including seasonal changes in supply and demand, weather conditions, market liquidity, governmental, regulatory, and environmental policies.

We manage the commodity price and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management policies. In managing commodity price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices. Our nuclear fleet is eligible for the nuclear PTC provided by the IRA which provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program.

VaR Methodology

A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.

Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level, (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions), and (iii) historical estimates of volatility and correlation data.

The following table summarizes the VaR for Vistra's commodity portfolio based on a 95% confidence level and an assumed holding period of 60 days. Average VaRs are the average of each month-end average for the years ended December 31, 2025 and 2024, respectively:
Year Ended December 31,
20252024
(in millions)
Average VaR$224 $236 
High VaR$316 $371 
Low VaR$138 $86 

Interest Rate Risk

We are exposed to fluctuations in interest rates through our issuance of variable rate debt. We mitigate our exposure to fluctuations in interest rates through entering interest rate swaps. These interest rate swaps limit the impact of interest rate changes on our results of operations and cash flows and lower our overall borrowing costs. Interest rate risk is managed centrally by our treasury function.

As of December 31, 2025, we have approximately $4.0 billion principal amount of variable rate debt consisting of the Vistra Operations Term Loan B-3 Facility, the BCOP Credit Facility, and the Vistra Zero Term Loan B Facility (see Note 11 to the Financial Statements for additional information). We have entered into net notional interest rate swaps that will hedge $2.3 billion of our exposure to Vistra Operations variable rate debt through December 2030 and $416 million of our project-level debt through October 2045 (see Note 13 to Financial Statements for additional information). As of December 31, 2025, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $13 million after taking into account the interest rate swaps.

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VISTRA CORP.
Credit Risk

Our primary concentration of credit risk is associated with the collection of receivables resulting from sales to retail customers and the risk of a counterparty's failure to meet its obligations under derivative contracts. We minimize our exposure to credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial conditions, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 13 to the Financial Statements for additional information.

Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets (liabilities) arising from commodity contracts and hedging and trading activities totaled $2.651 billion as of December 31, 2025. Including collateral posted to us by counterparties, our net exposure was $2.494 billion, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of December 31, 2025. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.
December 31, 2025
Exposure Before Credit Collateral
Trade Accounts ReceivableDerivativesGross
Exposure		Credit
Collateral		Net
Exposure
(in millions)
Retail segment
$1,831 $(16)$1,815 $48 $1,767 
Texas, East, West, and Asset Closure segments:
Investment grade$189 $448 $637 $5 $632 
Below investment grade or no rating133 66 199 104 95 
Texas, East, West, and Asset Closure segments
$322 $514 $836 $109 $727 
Total
$2,153 $498 $2,651 $157 $2,494 

Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements and are excluded from the detail above. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.

An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us. Significant (i.e., 10% or greater) concentration of credit exposure exists with one counterparty, which represented an aggregate $331 million, or 46%, of our total net exposure as of December 31, 2025. We view exposure to this counterparty to be within an acceptable level of risk tolerance due to the counterparty's credit ratings, market role and deemed creditworthiness and the importance of our business relationship with the counterparty.

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VISTRA CORP.
Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2025 and 2024.
Year Ended December 31,
20252024
(in millions)
Commodity contract net liability as of January 1$(1,460)$(2,740)
Mark-to-market adjustments:
Settlements/termination of positions (a)970 1,213 
Changes in fair value of positions in the portfolio (b)(1,778)(58)
Net gain (loss) associated with mark-to-market accounting
(808)1,155 
Acquired commodity contracts (c)(410)(50)
Other activity (d)102 175 
Commodity contract net liability as of December 31
$(2,576)$(1,460)
____________
(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains/(losses) recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(b)Represents unrealized net gains/(losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(c)Includes fair value of commodity contracts acquired in the Lotus Acquisition in 2025 and the Energy Harbor Merger in 2024 (see Note 2 to the Financial Statements for additional information).
(d)Primarily represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.

The following maturity table presents the net commodity contract liability arising from recognition of fair values as of December 31, 2025, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
Maturity dates of unrealized commodity contract net liability as of December 31, 2025
Source of Fair ValueLess than
1 year		1-3 years4-5 yearsExcess of
5 years		Total
(in millions)
Prices actively quoted$(556)$(332)$(11)$1 $(898)
Prices provided by other external sources(194)(214)(1)— (409)
Prices based on models(163)(536)(287)(283)(1,269)
Total$(913)$(1,082)$(299)$(282)$(2,576)

We have engaged in natural gas hedging activities to mitigate the risk of higher or lower wholesale electricity prices that have corresponded to increases or declines in natural gas prices. When natural gas prices are elevated or depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.

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Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Vistra Corp.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Vistra Corp. and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in equity, for each of the three years in the period ended December 31, 2025, and the related notes and the schedule listed in the Index at Item 15(b) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2026, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Fair Value Measurements — Certain Complex Level 3 Derivative Assets and Liabilities — Refer to Notes 1, 13 and 14 to the financial statements

Critical Audit Matter Description

The Company has derivative assets and liabilities whose fair values are based on complex proprietary models and/or unobservable inputs. These financial instruments can span a broad array of contract types, some of which include especially complex valuations due to unique contract terms and significant judgements by management in estimating prices or volumes, including (1) power purchases and sales that include power and heat rate positions; (2) physical power and natural gas options and swaptions; (3) forward purchase contracts for congestion revenue rights; and (4) retail sales contracts. Under accounting principles generally accepted in the United States of America, these financial instruments are generally classified as Level 3 derivative assets or liabilities.

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Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of the aforementioned Level 3 derivative assets and liabilities, performing audit procedures to evaluate the reasonableness of the fair value of Level 3 derivative assets and liabilities required a high degree of auditor judgment and an increased extent of effort, including the need to involve our energy commodity fair value specialists who possess significant quantitative and modeling expertise.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the evaluation of the fair value of Level 3 derivative assets and liabilities included the following, among others:

•We tested the effectiveness of internal control over derivative asset and liability valuations, including internal control related to appropriate application of illiquid price curves and other significant unobservable valuation inputs.

•We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2025, to obtain an understanding of the types of instruments outstanding.

•We assessed the consistency by which management has applied illiquid price curves and significant unobservable valuation inputs.

•With the assistance of our energy commodity fair value specialists, we developed independent estimates of the fair value of a sample of Level 3 derivative instruments and compared our estimates to the Company's estimates.

/s/ Deloitte & Touche LLP

Dallas, Texas
February 26, 2026

We have served as the Company’s auditor since 2002.

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VISTRA CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions of Dollars, Except Share Data)
Year Ended December 31,
202520242023
Operating revenues$17,738 $17,224 $14,779 
Fuel, purchased power costs, and delivery fees(9,101)(7,285)(7,557)
Operating costs(2,803)(2,414)(1,702)
Depreciation and amortization(1,986)(1,843)(1,502)
Selling, general, and administrative expenses(1,714)(1,601)(1,308)
Impairment of long-lived assets(228)— (49)
Operating income1,906 4,081 2,661 
Other income, net394 291 243 
Interest expense and related charges(1,179)(900)(740)
Impacts of Tax Receivable Agreement2 (5)(164)
Net income before income taxes1,123 3,467 2,000 
Income tax expense(179)(655)(508)
Net income944 2,812 1,492 
Net (income) loss attributable to noncontrolling interest and redeemable noncontrolling interest— (153)1 
Net income attributable to Vistra944 2,659 1,493 
Cumulative dividends attributable to preferred stock(192)(192)(150)
Net income attributable to Vistra common stock$752 $2,467 $1,343 
Weighted average shares of common stock outstanding:
Basic
339,124,917 344,788,634 369,771,359 
Diluted
345,656,067 352,567,060 375,193,110 
Net income per weighted average share of common stock outstanding:
Basic$2.22 $7.16 $3.63 
Diluted$2.18 $7.00 $3.58 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)
Year Ended December 31,
202520242023
Net income$944 $2,812 $1,492 
Other comprehensive income (loss), net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense of $—, $4 and $—)
(3)14 (1)
Total other comprehensive income (loss)(3)14 (1)
Comprehensive income941 2,826 1,491 
Comprehensive (income) loss attributable to noncontrolling interest and redeemable noncontrolling interest— (153)1 
Comprehensive income attributable to Vistra$941 $2,673 $1,492 

See Notes to the Consolidated Financial Statements
79

VISTRA CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Share Data)
December 31,
20252024
ASSETS
Current assets:
Cash and cash equivalents$785 $1,188 
Restricted cash31 28 
Trade accounts receivable — net2,323 1,982 
Inventories — net
Materials and supplies
599 533 
Fuel stock and natural gas in storage
417 437 
Commodity and other derivative contractual assets2,793 2,587 
Margin deposits related to commodity contracts1,133 406 
Margin deposits posted under affiliate financing agreement444 435 
Prepaid expense and other current assets654 523 
Total current assets9,179 8,119 
Restricted cash6 6 
Investments5,091 4,512 
Property, plant, and equipment — net19,846 18,173 
Goodwill2,810 2,807 
Identifiable intangible assets — net2,435 2,213 
Commodity and other derivative contractual assets405 740 
Accumulated deferred income taxes239 9 
Other noncurrent assets1,539 1,191 
Total assets$41,550 $37,770 
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings$1,800 $— 
Accounts receivable financing1,225 750 
Long-term debt due currently1,201 880 
Forward repurchase obligation due currently632 703 
Trade accounts payable1,644 1,510 
Commodity and other derivative contractual liabilities4,049 3,351 
Margin deposits related to commodity contracts7 49 
Accrued taxes other than income224 209 
Accrued interest188 193 
Asset retirement obligations181 142 
Other current liabilities663 645 
Total current liabilities11,814 8,432 
Margin deposits financing with affiliate444 435 
Long-term debt, less amounts due currently15,842 15,418 
Forward repurchase obligation, less amounts due currently— 632 
Commodity and other derivative contractual liabilities1,729 1,367 
Accumulated deferred income taxes1,049 697 
Asset retirement obligations4,035 3,936 
Other noncurrent liabilities and deferred credits1,527 1,270 
Total liabilities36,440 32,187 
See Notes to the Consolidated Financial Statements
80

VISTRA CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Share Data)
December 31,
20252024
Commitments and Contingencies
Total equity:
Preferred stock (100,000,000 shares authorized, $1,000 liquidation preference per share, 2,476,066 shares outstanding at both December 31, 2025 and 2024, respectively)
2,476 2,476 
Common stock (par value $0.01 per share, 1,800,000,000 shares authorized, 338,059,635 and 339,754,307 shares outstanding at December 31, 2025 and 2024, respectively)
5 5 
Treasury stock, at cost (215,599,525 and 208,998,299 shares at December 31, 2025 and 2024, respectively)
(6,925)(5,912)
Additional paid-in-capital9,536 9,435 
Accumulated deficit(12)(454)
Accumulated other comprehensive income17 20 
Stockholders' equity5,097 5,570 
Noncontrolling interest in subsidiary13 13 
Total equity5,110 5,583 
Total liabilities and equity$41,550 $37,770 

See Notes to the Consolidated Financial Statements
81

VISTRA CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
202520242023
Cash flows — operating activities:
Net income$944 $2,812 $1,492 
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization2,950 2,631 1,956 
Deferred income tax expense (benefit), net136 607 457 
Gain on sale of land— — (95)
Impairment of long-lived and other assets228 — 49 
Unrealized net (gain) loss from mark-to-market valuations of commodities808 (1,155)(490)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps67 (53)36 
Unrealized net gain from nuclear decommissioning trusts(138)(116)— 
Change in asset retirement obligation liability(20)38 27 
Asset retirement obligation accretion expense134 114 34 
Impacts of Tax Receivable Agreement(2)5 164 
Gain on TRA repurchase and tender offers— (10)(29)
Bad debt expense201 183 164 
Stock-based compensation expense113 100 77 
Involuntary conversion gain(120)— — 
Other, net(47)(89)103 
Changes in operating assets and liabilities:
Accounts receivable — trade(528)(242)214 
Inventories(3)(31)(174)
Accounts payable — trade16 19 (350)
Commodity and other derivative contractual assets and liabilities(102)(175)82 
Margin deposits, net(769)842 1,899 
Accrued interest(4)(18)46 
Accrued taxes27 (1)5 
Accrued employee incentive(40)8 58 
Asset retirement obligation settlement(96)(88)(81)
Major plant outage deferral7 (91)(32)
Other — net assets88 (616)84 
Other — net liabilities220 (111)(243)
Cash provided by operating activities4,070 4,563 5,453 
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments(2,752)(2,078)(1,676)
Lotus acquisition (net of cash acquired)(1,140)— — 
Energy Harbor acquisition (net of cash acquired)— (3,065)— 
Proceeds from sales of nuclear decommissioning trust fund securities5,153 2,216 601 
Investments in nuclear decommissioning trust fund securities(5,177)(2,239)(624)
Proceeds from sales of environmental allowances275 773 500 
Purchases of environmental allowances(1,189)(1,226)(1,071)
Insurance proceeds for recovery of damaged property, plant, and equipment325 3 15 
See Notes to the Consolidated Financial Statements
82

VISTRA CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
202520242023
Proceeds from sales of property, plant, and equipment, including nuclear fuel119 196 115 
Proceeds from sales of transferable ITCs— 150 — 
Other, net(10)(6)(5)
Cash used in investing activities(4,396)(5,276)(2,145)
Cash flows — financing activities:
Issuances of debt2,506 3,817 2,498 
Repayments/repurchases of debt(2,584)(2,287)(33)
Net borrowings (repayments) under accounts receivable financing475 750 (425)
Borrowings under Revolving Credit Facility530 50 100 
Repayments under Revolving Credit Facility(150)(50)(350)
Borrowings under Commodity-Linked Facility2,507 1,802 — 
Repayments under Commodity-Linked Facility(1,087)(1,802)(400)
Debt issuance costs(23)(76)(59)
Stock repurchases(1,028)(1,266)(1,245)
Dividends paid to common stockholders(306)(305)(313)
Dividends paid to preferred stockholders(192)(173)(150)
Dividends paid to noncontrolling and redeemable noncontrolling interest holders— (180)— 
Payment for acquisition of noncontrolling interest— (1,748)— 
Principal payment on forward repurchase obligation(703)— — 
TRA Repurchase and tender offer — return of capital— (122)— 
Other, net(19)(14)83 
Cash used in financing activities(74)(1,604)(294)
Net change in cash, cash equivalents, and restricted cash (current and noncurrent)(400)(2,317)3,014 
Cash, cash equivalents, and restricted cash (current and noncurrent) — beginning balance1,222 3,539 525 
Cash, cash equivalents, and restricted cash (current and noncurrent) — ending balance$822 $1,222 $3,539 
Supplemental Cash Flow Information:
Cash payments related to:
Interest paid
$1,165 $987 $636 
Capitalized interest
(125)(77)(37)
Interest paid (net of capitalized interest)
$1,040 $910 $599 
Non-cash investing and financing activities:
Accrued property, plant, and equipment additions (a)
$108 $258 $104 
Issuance of Series C Preferred Stock as consideration for the repurchase of TRA Rights with a carrying value of $506 million
$— $— $476 

See Notes to the Consolidated Financial Statements
83

VISTRA CORP.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Millions of Dollars)
Preferred StockCommon StockTreasury StockAdditional Paid-In Capital
Accumulated Deficit
Accumulated Other Comprehensive Income (Loss)Total Stockholders' EquityNoncontrolling Interest in SubsidiaryTotal Equity
Balances at
December 31, 2022
$2,000 $5 $(3,395)$9,928 $(3,643)$7 $4,902 $16 $4,918 
Series C Preferred Stock issued476 — — — — — 476 — 476 
Stock repurchases— — (1,267)— — — (1,267)— (1,267)
Effects of stock-based incentive compensation plans (a)— — — 168 — — 168 — 168 
Net income (loss)— — — — 1,493 — 1,493 (1)1,492 
Dividends declared on common stock— — — — (313)— (313)— (313)
Dividends declared on preferred stock— — — — (150)— (150)— (150)
Change in accumulated other comprehensive income— — — — — (1)(1)— (1)
Other— — — (1)— — (1)— (1)
Balances at
December 31, 2023
$2,476 $5 $(4,662)$10,095 $(2,613)$6 $5,307 $15 $5,322 
Stock repurchases— — (1,250)— — — (1,250)— (1,250)
Effects of stock-based incentive compensation plans (a)— — — 140 — — 140 — 140 
Net income
— — — — 2,659 — 2,659 102 2,761 
Dividends declared on common stock— — — — (307)— (307)— (307)
Dividends declared on preferred stock— — — — (192)— (192)— (192)
Dividends to noncontrolling interest— (15)(15)
Change in accumulated other comprehensive income— — — — — 14 14 — 14 
Equity issued in subsidiary to acquire Energy Harbor— — — 747 — — 747 1,560 2,307 
Modification of noncontrolling interest to redeemable noncontrolling interest (b)— — — (1,539)— — (1,539)(1,659)(3,198)
Other— — — (8)(1)— (9)10 1 
Balances at
December 31, 2024
$2,476 $5 $(5,912)$9,435 $(454)$20 $5,570 $13 $5,583 
Stock repurchases(1,013)(1,013)(1,013)
Effects of stock-based incentive compensation plans (a)— — — 102 — — 102 — 102 
Net income— — — — 944 — 944 — 944 
Dividends declared on common stock— — — — (308)— (308)— (308)
Dividends declared on preferred stock— — — — (192)— (192)— (192)
See Notes to the Consolidated Financial Statements
84

VISTRA CORP.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Millions of Dollars)
Preferred StockCommon StockTreasury StockAdditional Paid-In Capital
Accumulated Deficit
Accumulated Other Comprehensive Income (Loss)Total Stockholders' EquityNoncontrolling Interest in SubsidiaryTotal Equity
Change in accumulated other comprehensive income— — — — — (3)(3)— (3)
Other— — — (1)(2)— (3)— (3)
Balances at
December 31, 2025
$2,476 $5 $(6,925)$9,536 $(12)$17 $5,097 $13 $5,110 
____________
(a)Includes cash payments to cover tax withholding obligations upon the vesting of stock-based incentive compensation plans of $52 million, $12 million, and $4 million for the years ended December 31, 2025, 2024 and 2023, respectively.
(b)See Note 2 for additional information regarding activity associated with noncontrolling interest.
See Notes to the Consolidated Financial Statements
85
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of 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.

Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management, and retail sales of electricity and natural gas to end users.

Vistra has five reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. See Note 21 for additional information.

Significant Accounting Policies

Basis of Presentation

The consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2024 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform with the current year presentation.

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities as of the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgments related to the potential timing of events, and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.

Business Combinations

The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value as of the acquisition date. The excess of the purchase price over those fair values is recognized as goodwill (if any). During the measurement period, which may be up to one year from the acquisition date, we may record adjustments to the assets acquired and liabilities assumed in the period in which they are determined. See Note 2 for additional information.

Derivative Instruments and Mark-to-Market Accounting

We enter derivative instruments, including commodity contracts and interest rate swaps, to manage commodity price and interest rate 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. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed.

A commodity-related 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.

86
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We report derivative instruments in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities on a gross basis without taking into consideration netting arrangements we have with counterparties. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset derivative assets and liabilities, receivables and payables on settled positions, and collateral to reduce credit exposure between us and the counterparty.

Generally, margin deposits that contractually offset derivative instruments are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral.

We report commodity hedging and trading results as revenue, fuel expense, or purchased power in the consolidated statements of operations depending on the type of activity. Electricity hedges, financial natural gas hedges, and trading activities are primarily reported as revenue. Physical hedges for coal or fuel oil, along with physical natural gas trades, are primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swap transactions are reported in the consolidated statements of operations in interest expense. See Note 13 for additional information.

Revenue Recognition

Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.

We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO/RTO, ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response available for system reliability requirements, and certain other electricity sales contracts. See Note 3 for additional information. See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts.

Government Grants

The Company qualifies for tax incentives through eligible construction spending and production through the Inflation Reduction Act of 2022 (IRA). These tax incentives generally provide for transferable tax credits upon the applicable qualifying event for the credit type, typically production or in-service date. We account for transferable ITCs and PTCs we expect to receive by analogy to ASC 832, Government Grants as amended by Accounting Standards Update (ASU) 2025-10 (ASC 832). Transferable PTCs are included in other noncurrent assets in the consolidated balance sheet and included in revenues in the consolidated statements of operations when receipt of the credit is probable. Transferable investment tax credits (ITCs) are included in other noncurrent assets on the consolidated balance sheet with a corresponding reduction to the cost basis of the Company's plant assets when receipt of the credit is probable, and reduces depreciation expense over the life of the asset. See Note 5 for additional information.

Major Maintenance Costs

Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in the consolidated statements of operations.

Defined Benefit Pension Plans and OPEB Plans

Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement of such employees from the company. Pension benefits are offered to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. See Note 16 for additional information.

87
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-Based Compensation

Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation. We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award. Forfeitures are recognized as they occur. See Note 17 for additional information.

Sales and Excise Taxes

Sales and excise taxes are accounted for as "pass through" items in the consolidated balance sheets with no effect on the consolidated statements of operations (i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction in other current liabilities in the consolidated statements of operations).

Franchise and Revenue-Based Taxes

Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in the consolidated statements of operations.

Income Taxes

Deferred income tax assets and liabilities are recorded to reflect, among other things, the temporary timing differences between the book basis and tax basis of assets and liabilities, as required under accounting rules. Investment tax credits that are not transferable are accounted for using the deferral method, which reduces the tax basis of our solar and battery storage facilities. As of December 31, 2025 and 2024, deferred tax assets related to these credits totaled $69 million and $69 million, respectively. We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 6 for additional information.

Accounting for Contingencies

Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 18 for additional information.

Cash, Cash Equivalents and Restricted Cash

For purposes of reporting cash and cash equivalents, temporary cash investments purchased with an original maturity of three months or less are considered cash equivalents. Restricted cash primarily consists of funds held in escrow accounts to fund asset retirement obligations of closed plant sites previously transferred to a third party remediation company.

Property, Plant, and Equipment

Property, plant, and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed. Significant improvements or additions to our property, plant, and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost.

Depreciation of our property, plant, and equipment (except for nuclear fuel) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives. See Note 7 for additional information.

88
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nuclear Fuel

Nuclear fuel is capitalized and reported as a component of our property, plant, and equipment in the consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs, and delivery fees in the consolidated statements of operations.

Impairment of Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss is recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 7 for additional information.

Goodwill and Intangible Assets with Indefinite Lives

As part of our fresh start reporting and purchase accounting from acquisitions, reorganization value or the purchase consideration is generally allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and liabilities, then any remaining excess reorganization value or purchase consideration is allocated to goodwill. We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. See Note 9 for additional information.

Asset Retirement Obligations (ARO)

A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. Changes in estimates related to assets that have been retired or for which costs are not recoverable are recorded as operating costs in the consolidated statements of operations. See Note 15 for additional information.

Inventories

Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects, respectively. Fuel stock and natural gas in storage are reported at the lower of cost (calculated on a weighted average basis) or net realizable value. We expect to recover the value of inventory costs in the normal course of business.

Nuclear Decommissioning Trust (NDT) Investments and Regulatory Assets or Liability

The NRC is responsible for regulating all nuclear power plants in the U.S. This regulatory oversight results in specific accounting considerations for nuclear plant decommissioning. Our NDTs hold funds primarily for the ultimate decommissioning of our nuclear power plants. Each unit has its own NDT and funds from one unit may not be used to fund decommissioning obligations of another unit.

Decommissioning costs associated with the Comanche Peak nuclear generation facility in Texas are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a wholly owned subsidiary of EFH Corp.) in the NDT. As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted for as rate regulated operations. Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liability balance that is reflected in the consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits.

89
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The NDTs associated with our PJM nuclear facilities have been funded with amounts collected from the previous owners and their respective utility customers. Any shortfall of funds necessary for decommissioning the PJM nuclear facilities, determined for each generating station unit, are required to be funded by us. Investments in the PJM NDTs are carried at fair value and gains and losses are recognized as other income or other deductions in the consolidated statements of operations. NDTs are invested in diversified portfolios of securities generally designed to achieve a return sufficient to fund the future decommissioning work. We retain any funds remaining in the trusts of the PJM nuclear facilities after all decommissioning has been completed.

Noncontrolling Interest and Redeemable Noncontrolling Interest in Subsidiary

A noncontrolling interest in a consolidated subsidiary represents the portion of the equity in a subsidiary not attributable, directly or indirectly, to the Company. Noncontrolling interests are presented as a separate component of equity in the consolidated balance sheets and the presentation of net income is modified to present earnings attributed to controlling and noncontrolling interests. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. See Note 2 for additional information.

Redeemable noncontrolling interests are presented as a component of temporary equity in the mezzanine section of the consolidated balance sheet and the presentation of net income is modified to present earnings attributed to the controlling and redeemable noncontrolling interest. In December 2024, we closed on the repurchase of the noncontrolling interest in Vistra Vision and reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation. See Notes 2 and 11 for additional information.

Treasury Stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in the consolidated balance sheets as a reduction to additional paid-in capital. Treasury stock purchases made by third party brokers on our behalf are recorded on a trade date basis when we are contractually obligated to pay the broker for their repurchase costs. See Note 19 for additional information.

Leases

At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration.

Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our secured incremental borrowing rate based on the information available at the lease commencement date to determine the present value of lease payments. Operating leases are included in other noncurrent assets, other current liabilities, and other noncurrrent liabilities and deferred credits on the consolidated balance sheet. Finance leases are included in property, plant, and equipment, other current liabilities and other noncurrent liabilities and deferred credits on the consolidated balance sheet. Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We apply the practical expedient permitted by ASC 842, Leases to not separate lease and non-lease components for a majority of our lease asset classes.

Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term.

90
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New Accounting Standards

Accounting for Government Grants

In December 2025, the Financial Accounting Standards Board (FASB) issued ASU No. 2025-10, Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities (ASU 2025-10), which provides guidance on recognition, measurement, and presentation of government grants. ASU 2025-10 is effective for annual periods beginning after December 15, 2028, including interim periods within those fiscal years. Early adoption is permitted. The Company adopted the amendments in this ASU for its fiscal year ended December 31, 2025. The adoption did not have a material impact on the consolidated financial statements as we previously accounted for ITCs and PTCs by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance, which the FASB largely leveraged in developing the ASU.

Derivatives Scope Refinements

In September 2025, the FASB issued ASU No. 2025-07 (ASU 2025-07), Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606). The amendments in the ASU exclude from derivative accounting certain non-exchange-traded contracts with underlyings that are based on operations or activities specific to one of the parties to the contract. The amendments also clarify that an entity should apply the guidance in Topic 606, including the guidance on non-cash consideration, to a contract with share-based non-cash consideration from a customer for the transfer of goods or services. The amendments are effective for fiscal years beginning after December 15, 2026, with early adoption permitted. The Company adopted the amendments in ASU 2025-07 prospectively for its fiscal year ended December 31, 2025 which resulted in certain wholesale contracts being excluded from derivative accounting.

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU No. 2023-09 (ASU 2023-09), Income Taxes (Topic 740): Improvements to Income Tax Disclosures to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024. The Company adopted ASU 2023-09 for its fiscal year ended December 31, 2025 and applied the new disclosure requirements in Note 6 on a retrospective basis.

Expense Disaggregation Disclosures

In November 2024, the FASB issued ASU No. 2024-03 (ASU 2024-03), Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve disclosures by providing additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and interim periods within annual reporting periods beginning after December 15, 2027 and can be applied prospectively or retrospectively. Early adoption is permitted. We are currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures.

Recent Developments

Debt, Credit Facilities, and Financing

Vistra Operations Senior Secured Notes — In January 2026, Vistra Operations issued $2.25 billion aggregate principal amount of senior secured notes, consisting of $1.0 billion aggregate principal amount of 4.700% senior secured notes due 2031 and $1.25 billion aggregate principal amount of 5.350% senior secured notes due 2036 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. See Note 11 for additional information.

91
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2.ACQUISITIONS

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.

The Lotus Acquisition was accounted for using the acquisition method in accordance with ASC 805, Business Combinations (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated fair values on the acquisition date. The total consideration transferred at closing, inclusive of adjustments to the base purchase price, was $1.237 billion as determined in accordance with ASC 805, which is subject to a final true-up. The combined results of operations are reported in the consolidated financial statements beginning as of the acquisition date.

In November 2025, the Company borrowed $800 million under the Commodity-Linked Credit Agreement (see Note 11 for additional information) to repay the approximately $800 million of debt assumed by the Company.

92
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Provisional fair value measurements were made for acquired assets and liabilities in the fourth quarter of 2025. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The provisional fair values assigned to the assets acquired and liabilities assumed are as follows:
Lotus Acquisition
Fair Value as of
October 22, 2025
(in millions)
Cash and cash equivalents$97 
Trade accounts receivables, inventories, prepaid expenses, and other current assets72 
Property, plant, and equipment (a)
2,346 
Other noncurrent assets22 
Total identifiable assets acquired2,537 
Trade accounts payable and other current liabilities21 
Long-term debt, including amounts due currently803 
Commodity and other derivative contractual liabilities (b)
417 
Asset retirement obligations
13 
Identifiable intangible liabilities23 
Other noncurrent liabilities and deferred credits23 
Total identifiable liabilities assumed1,300 
Net assets acquired$1,237 
(a)Acquired property, plant, and equipment are valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).
(b)Acquired derivatives are valued using the methods described in Note 13 (Level 1, Level 2, or Level 3).

The following unaudited pro forma financial information for the Company for the years ended December 31, 2025 and 2024 assumes that the Lotus Acquisition occurred on January 1, 2024. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Lotus Acquisition been completed on January 1, 2024, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.
Lotus Acquisition
Year Ended December 31,
20252024
(in millions)
Revenues$18,256 $17,626 
Net income$943 $2,787 

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, effects of the Lotus Acquisition on tax expense (benefit), and other related adjustments. Determining the amounts of revenue and earnings of the Lotus Acquisition since the acquisition date is impractical as operations have been integrated into our commercial platform which is managed at a portfolio level.

Acquisition-related costs incurred in the Lotus Acquisition totaled $17 million for the year ended December 31, 2025 and are classified as selling, general, and administrative expenses in the consolidated statements of operations.

93
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Energy Harbor Business Combination

On March 1, 2024, pursuant to a transaction agreement (Transaction Agreement), (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 Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (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 Energy Harbor Merger was accounted for using the acquisition method in accordance with ASC 805, Business Combinations (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated fair values on the Merger Date. The combined results of operations are reported in the consolidated financial statements beginning as of the Merger Date.

The following table summarizes the acquisition date fair value of Energy Harbor associated with the Energy Harbor Merger:
Consideration
(in millions)
Cash consideration$3,100 
15% of the fair value of net assets contributed to Vistra Vision by Vistra (a)
1,496 
Total purchase price4,596 
Fair value of noncontrolling interest in Energy Harbor (b)811 
Acquisition date fair value of Energy Harbor$5,407 
____________
(a)Valued using a discounted cash flow analysis of the contributed subsidiaries including contributed debt.
(b)Represents 15% of the acquisition date fair value implied from the fair value of consideration transferred.

As a result of the Energy Harbor Merger, Vistra maintained an 85% ownership interest in Vistra Vision and recorded the remaining 15% equity interest as a noncontrolling interest in the consolidated balance sheets, and we reclassified the carrying value of assets contributed to Vistra Vision of $749 million from additional paid-in-capital of Vistra (the controlling interest) to the noncontrolling interest in subsidiary.

94
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Provisional fair value measurements were made for acquired assets and liabilities in the first quarter of 2024 and adjustments to those measurements were made through March 1, 2025 (the end of the measurement period). The final fair values assigned to assets acquired and liabilities assumed are as follows:
Energy Harbor Merger
Fair Value as of
March 1, 2024
Measurement Period Adjustments
(in millions)
Cash and cash equivalents$35 $5 
Trade accounts receivables, inventories, prepaid expenses, and other current assets540 2 
Investments (a)2,021 — 
Property, plant, and equipment (b)5,616 (4)
Identifiable intangible assets (c)444 16 
Commodity and other derivative contractual assets (d)129 (11)
Other noncurrent assets62 54 
Total identifiable assets acquired8,847 62 
Trade accounts payable and other current liabilities318 55 
Long-term debt, including amounts due currently413 — 
Commodity and other derivative contractual liabilities (d)179 — 
Accumulated deferred income taxes1,314 (50)
Asset retirement obligations (e)1,368 — 
Identifiable intangible liabilities55 (18)
Other noncurrent liabilities and deferred credits20 8 
Total identifiable liabilities assumed3,667 (5)
Identifiable net assets acquired5,180 67 
Goodwill (f)227 (67)
Net assets acquired$5,407 
____________
(a)Investments represent securities held in nuclear decommissioning trusts (NDT) for the purpose of funding the future retirement and decommissioning of the PJM nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC. They are valued using a market approach (Level 1 or Level 2 depending on security).
(b)Acquired property, plant, and equipment are valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).
(c)Includes acquired nuclear fuel supply contracts valued based on contractual cash flow projections over approximately five years compared with cash flows based on current market prices with the resulting difference discounted to present value (Level 3). Also includes acquired retail customer relationships which are valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3).
(d)Acquired derivatives are valued using the methods described in Note 13 (Level 1, Level 2, or Level 3). Contracts with terms that were not at current market prices are also valued using a discounted cash flow analysis (Level 3).
(e)Asset retirement obligations are valued using a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies (Level 3).
(f)The excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed is recorded as goodwill. Goodwill represents expected synergies to be generated from combining operations of Energy Harbor with Vistra. None of the Goodwill is deductible for income tax purposes.

95
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma financial information for the Company for the years ended December 31, 2024 and 2023 assumes that the Energy Harbor Merger occurred on January 1, 2023. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Energy Harbor Merger been completed on January 1, 2023, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.
Energy Harbor Merger
Year Ended December 31,
20242023
(in millions)
Revenues$17,948 $17,148 
Net income$2,901 $1,398 

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Energy Harbor Merger, effects of the Energy Harbor Merger on tax expense (benefit), and other related adjustments. Determining the amounts of revenue and earnings of Energy Harbor since the acquisition date is impractical as operations have been integrated into our commercial platform which is managed at a portfolio level.

Acquisition-related costs incurred in the Energy Harbor Merger totaled $25 million for the year ended December 31, 2024 and are classified as selling, general, and administrative expenses in the consolidated statements of operations.

Acquisition of Noncontrolling Interest

On September 18, 2024, Vistra Operations and Vistra Vision Holdings I LLC, an indirect wholly owned subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (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. The UPAs contained certain closing conditions outside our control that represented conditional redemption obligations that required us to reflect the transaction as redeemable noncontrolling interest within the mezzanine section of the consolidated balance sheet as of September 30, 2024. The UPAs were amended prior to close to accelerate principal payments to Avenue and certain Nuveen noncontrolling interest holders. The transaction closed on December 31, 2024, with all closing conditions met. Upon closing, we reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation. See Note 11 for additional information.

96
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3.REVENUE

Revenue Disaggregation

The following tables disaggregate our revenue by major source:
Year Ended December 31, 2025
RetailTexasEastWestAsset ClosureEliminations / Corporate and OtherConsolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT$8,966 $— $— $— $— $— $8,966 
Retail energy charge in Northeast/Midwest4,059 — — — — — 4,059 
Wholesale generation revenue from ISO/RTO— 464 2,626 98 — — 3,188 
Capacity revenue from ISO/RTO (a)— — 227 — — — 227 
Revenue from other wholesale contracts— 454 458 230 4 — 1,146 
Total revenue from contracts with customers13,025 918 3,311 328 4 — 17,586 
Other revenues:
Transferable PTC revenues (b)— 229 — — — — 229 
Hedging revenues — realized1,210 (440)(303)116 — — 583 
Hedging revenue — unrealized(2)182 (826)(122)2 — (766)
Business interruption insurance proceeds— 47 — — 71 — 118 
Intangible amortization and other revenues— (2)(13)— — 3 (12)
Intersegment sales (c)107 4,419 4,005 3 (3)(8,531)— 
Total other revenues1,315 4,435 2,863 (3)70 (8,528)152 
Total revenues$14,340 $5,353 $6,174 $325 $74 $(8,528)$17,738 
____________
(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $793 million of capacity sold offset by $566 million of capacity purchased. Net capacity purchased in each ISO/RTO, as applicable, included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $130 million offset by $63 million of capacity sold within the East segment.
(b)Represents transferable PTCs generated from qualifying nuclear and solar assets during the period.
(c)East segment includes $147 million of intersegment unrealized net losses, and Texas segment includes $293 million of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

97
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31, 2024
RetailTexasEast (a)WestAsset ClosureEliminations / Corporate and OtherConsolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT$8,064 $— $— $— $— $— $8,064 
Retail energy charge in Northeast/Midwest (a)
3,595 — — — — — 3,595 
Wholesale generation revenue from ISO/RTO— 399 1,351 221 7 — 1,978 
Capacity revenue from ISO/RTO (b)
— — 74 — — — 74 
Revenue from other wholesale contracts— 422 398 199 31 — 1,050 
Total revenue from contracts with customers11,659 821 1,823 420 38 — 14,761 
Other revenues:
Transferable PTC revenues (c)
— 292 264 — — — 556 
Hedging revenues — realized1,241 (453)31 84 (8)— 895 
Hedging revenue — unrealized(168)700 143 329 9 — 1,013 
Intangible amortization and other revenues1 — (4)— — 2 (1)
Intersegment sales (d)
64 4,034 3,404 6 — (7,508)— 
Total other revenues1,138 4,573 3,838 419 1 (7,506)2,463 
Total revenues$12,797 $5,394 $5,661 $839 $39 $(7,506)$17,224 
____________
(a)Includes ten months of revenue associated with operations acquired in the Energy Harbor Merger.
(b)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $126 million of capacity sold offset by $52 million of capacity purchased. Net capacity purchased in each ISO/RTO, as applicable, included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $139 million offset by $116 million of capacity sold within the East segment.
(c)Represents transferable PTCs generated from qualifying nuclear and solar assets during the period.
(d)East segment includes $195 million of intersegment unrealized net losses, and Texas and West segments include $74 million and $4 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

98
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31, 2023
RetailTexasEast (a)WestAsset ClosureEliminations / Corporate and OtherConsolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT$7,674 $— $— $— $— $— $7,674 
Retail energy charge in Northeast/Midwest1,642 — — — — — 1,642 
Wholesale generation revenue from ISO/RTO— 1,190 1,298 412 9 — 2,909 
Capacity revenue from ISO/RTO (a)— — 98 — — — 98 
Revenue from other wholesale contracts— 505 797 143 36 — 1,481 
Total revenue from contracts with customers9,316 1,695 2,193 555 45 — 13,804 
Other revenues:
Transferable PTC revenues
— 10 — — — — 10 
Hedging revenues — realized1,063 (885)43 64 (33)— 252 
Hedging revenue — unrealized191 (714)958 243 36 — 714 
Intangible amortization and other revenues2 — (5)— — 2 (1)
Intersegment sales (b)
— 3,873 2,701 4 — (6,578)— 
Total other revenues1,256 2,284 3,697 311 3 (6,576)975 
Total revenues$10,572 $3,979 $5,890 $866 $48 $(6,576)$14,779 
____________
(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $233 million of capacity sold offset by $135 million of capacity purchased. Net capacity purchased in each ISO/RTO, as applicable, included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $82 million offset by $73 million of capacity sold within the East segment.
(b)East segment includes $814 million of intersegment unrealized net gains and Texas and West segments include $48 million and $6 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Retail Energy Charges

Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 60 days from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation.

Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.

As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.

99
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Wholesale Generation Revenue from ISOs/RTOs and Revenue from Other Wholesale Contracts

Wholesale generation revenue is recognized when volumes are delivered to the ISO/RTO. Other wholesale contracts include other revenue activity with the ISO/RTO, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers, municipalities or other wholesale counterparties. Wholesale revenues are recognized over time using the output method based on kilowatt hours delivered or other applicable performance measurements and cash is settled shortly after invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Wholesale revenues are delivered as a series of distinct services and are accounted for as a single performance obligation. When electricity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in wholesale generation revenues.

Capacity Revenue From ISO/RTO

We offer generation capacity into competitive ISO/RTO auctions in exchange for revenue from awarded capacity offers. Capacity ensures installed generation and demand response is available to satisfy system integrity and reliability requirements. Capacity revenues are recognized when the performance obligation is satisfied ratably over time as our power generation facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO/RTO against generation facilities if the facility is not available during the capacity period and are recorded as a reduction to revenue. When capacity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in capacity revenue from ISO/RTO.

Other Revenues

Other revenues, as included in the tables of disaggregated revenue above, represent amounts not accounted for under ASC 606, Revenue from Contracts with Customers and are comprised of the following:

•Transferable production tax credit revenues accounted for as grants related to income by analogy to ASC 832 (see Note 5 for additional information).
•Intangible amortization of acquired intangible liabilities related to retail and wholesale contracts (see Note 9 for additional information).
•Hedging revenue from electricity and natural gas derivative contracts accounted for under ASC 815, Derivatives and Hedging, including the impact of realized and unrealized gains or losses on those contracts (see Note 13 for additional information).
•Intersegment sales are presented by segment and eliminated in consolidation.

Contract and Other Customer Acquisition Costs

We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of December 31, 2025 and 2024 was $129 million and $114 million, respectively. The amortization related to these costs during the years ended December 31, 2025, 2024 and 2023 totaled $111 million, $97 million, and $88 million respectively, recorded as SG&A expenses, and $7 million, $6 million, and $6 million, respectively, recorded as a reduction to operating revenues in the consolidated statements of operations.

Practical Expedients

The majority of our revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient. We have elected to not disclose the value of unsatisfied performance obligations for contracts with variable consideration for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar customer contracts with similar performance obligations. Sales taxes are not included in revenue.

100
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Performance Obligations

As of December 31, 2025, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or capacity contracts with customers for which the total consideration is fixed and determinable at contract execution. Capacity revenues are recognized when the performance obligations to provide capacity to the relevant ISOs/RTOs or counterparties are fulfilled. Amounts with counterparties in the table below represent minimum guaranteed capacity revenues as determined on a contract by contract basis and do not represent the full amount of capacity that is expected to be delivered.

20262027202820292030
2031 and Thereafter
Total
(in millions)
Remaining performance obligations$1,768 $1,665 $733 $215 $215 $3,293 $7,889 

Trade Accounts Receivable
December 31,
20252024
(in millions)
Wholesale and retail trade accounts receivable$2,412 $2,061 
Allowance for credit losses(89)(79)
Trade accounts receivable — net$2,323 $1,982 
Trade accounts receivable from contracts with customers — net$1,826 $1,514 
Other trade accounts receivable — net497 468 
     Total trade accounts receivable — net $2,323 $1,982 

Gross trade accounts receivable as of December 31, 2025 and December 31, 2024 include unbilled retail revenues of $924 million and $802 million, respectively.

Allowance for Credit Losses on Accounts Receivable
Year Ended December 31,
202520242023
(in millions)
Allowance for credit losses on accounts receivable at beginning of period$79 $61 $65 
Increase for bad debt expense201 183 164 
Decrease for account write-offs(191)(165)(168)
Allowance for credit losses on accounts receivable at end of period$89 $79 $61 

4.OTHER INCOME, NET

Year Ended December 31,
202520242023
(in millions)
NDT net income (a)$231 $170 $— 
Insurance settlements (b)120 23 24 
Gain on sale of land (c)— 6 95 
Gain on TRA settlement (d)— 10 29 
Interest income18 65 86 
All other25 17 9 
Total other income, net$394 $291 $243 
____________
(a)Includes interest, dividends, and net realized and unrealized gains (losses) associated with NDTs of the PJM nuclear facilities. Reported in the East segment.
101
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(b)For the year ended December 31, 2025, represents involuntary conversion gain for Martin Lake Incident insurance proceeds reported in the Texas Segment (see Note 8 for additional information). For the year ended December 31, 2024, $20 million reported in the Texas segment and $3 million reported in the West segment. For the year ended December 31, 2023, $19 million reported in the West segment and $5 million in the Asset Closure segment.
(c)For the year ended December 31, 2024, reported in the Asset Closure segment. For the year ended December 31, 2023, $94 million reported in the Asset Closure segment and $1 million reported in the Texas segment.
(d)Reported in the Corporate and Other.

5.GOVERNMENT GRANTS

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S. enacted the IRA, which introduced various energy tax credits. Among these, it acknowledged the importance of existing carbon-free nuclear power by establishing a nuclear Production Tax Credit under section 45U (nuclear PTC), a solar PTC, new technology-neutral ITCs and PTCs that apply to various different clean energy technologies, and a new stand-alone battery storage investment tax credit. The nuclear PTC 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. The nuclear PTC applies to existing nuclear facilities from 2024 through 2032 subject to an annual inflation adjustment. The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to ASC 832.

Transferable PTCs

In the years ended December 31, 2025 and 2024, we recognized transferable nuclear PTC revenues of $220 million and $545 million, respectively. Nuclear PTC revenues are an estimate based on annual gross receipts generated from qualifying nuclear production in 2025 and 2024 and reflect our determination that we will meet the prevailing wage requirements necessary to earn the five times multiplier. Our computation of gross receipts includes settled spot energy revenues and capacity revenues (applicable to our PJM nuclear units only) at each nuclear unit and excludes any hedges and ancillary service revenue. Treasury regulations may 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 estimate could result in a material change to PTC revenues recorded in 2025 and 2024 and would be reflected as a change in estimate in the period in which the guidance is received.

Transferable ITCs

In October 2025, our Oak Hill 200 MW solar facility in Texas met the requirements to be placed in service. As a result, in the year ended December 31, 2025, we recognized $98 million of transferable ITCs associated with the project in other noncurrent assets in the consolidated balance sheet.

In December 2024, our Baldwin 68 MW solar / 2 MW battery ESS and Coffeen 44 MW solar / 2 MW battery ESS facilities in Illinois met requirements to be placed in service. As a result, in the years ended December 31, 2025 and 2024, we recognized transferable ITCs of $(2) million and $57 million, respectively, associated with Baldwin, and $(1) million and $45 million, respectively, associated with Coffeen, in other noncurrent assets in the consolidated balance sheet.

In June 2023, our 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III) in California commenced commercial operations. As a result of Moss Landing Phase III meeting requirements to be placed in service in June 2023, we recognized $154 million of transferable ITCs associated with the project in other noncurrent assets in the consolidated balance sheet. In September 2024, we recognized an additional $2 million of transferable ITCs associated with the project and reclassified the $156 million of credits to other current assets.

Sales of Transferable PTCs and ITCs

During 2025, we sold $490 million of transferable nuclear PTCs recognized from qualifying 2024 nuclear generation, of which $200 million was sold in January 2025, $90 million was sold in May and June 2025, and $200 million was sold in September 2025. Cash proceeds of $469 million were received during the year ended December 31, 2025.

In October 2024, we sold $156 million of transferable ITCs and $10 million of transferable solar PTCs generated in 2023. Vistra received cash consideration from the sale in October 2024.

102
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6.INCOME TAXES

Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra serves as the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.

Income Tax Expense (Benefit)

The components of our income tax expense (benefit) are as follows:
Year Ended December 31,
202520242023
(in millions)
Current:
U.S. Federal$(3)$2 $(1)
State46 46 52 
Total current43 48 51 
Deferred:
U.S. Federal149 561 421 
State(13)46 36 
Total deferred136 607 457 
Total$179 $655 $508 

Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded:
Year Ended December 31,
202520242023
(in millions)
Income (loss) before income taxes$1,123 $3,467 $2,000 
Income taxes at the U.S. federal statutory rate of 21%236 21.0 %728 21.0 %420 21.0 %
State and local taxes, net of federal benefit (a)26 2.3 %68 2.0 %71 3.6 %
Nontaxable or nondeductible items:
Nondeductible TRA accretion(1)(0.1)%2 0.1 %41 2.1 %
Equity awards(145)(12.9)%(53)(1.6)%(3)(0.2)%
Nondeductible 162(m) compensation75 6.7 %29 0.8 %13 0.7 %
Transferable PTC revenues(46)(4.1)%(117)(3.4)%(2)(0.1)%
Other nontaxable or nondeductible items7 0.6 %2 0.1 %2 0.1 %
Changes in valuation allowance— — %(3)(0.1)%— — %
Changes in unrecognized tax benefit— — %— — %(35)(1.8)%
Tax credits
(3)(0.3)%— — %(1)(0.1)%
Other30 2.7 %(1)— %2 0.1 %
Total$179 15.9 %$655 18.9 %$508 25.4 %
____________
(a)State and local taxes in Texas, Pennsylvania, and Illinois comprise the majority of this category.

103
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income Taxes Paid (Net of Refunds)
Year Ended December 31,
202520242023
(in millions)
US Federal$11 $5 $— 
(a)
US state and local
California11 3 5 
Illinois— 
(a)
14 15 
Massachusetts— 
(a)
4 3 
Ohio Municipalities21 — 
(a)
— 
(a)
Pennsylvania28 6 5 
Texas19 17 — 
(a)
Other7 6 3 
Total US state and local
$86 $50 $31 
Total
$97 $55 $31 
____________
(a)Income taxes paid did not meet the 5% disaggregation threshold for the periods presented.

Deferred Income Tax Balances

Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2025 and 2024 are as follows:
December 31,
20252024
(in millions)
Noncurrent Deferred Income Tax Assets
Tax credit carryforwards$89 $86 
Loss carryforwards1,078 949 
Identifiable intangible assets326 340 
Long-term debt130 225 
Employee benefit obligations133 133 
Commodity contracts and interest rate swaps661 383 
Other37 36 
Total deferred tax assets$2,454 $2,152 
Noncurrent Deferred Income Tax Liabilities
Property, plant, and equipment3,191 2,765 
Total deferred tax liabilities3,191 2,765 
Valuation allowance73 75 
Net Deferred Income Tax Liability$(810)$(688)

As of December 31, 2025, we had total net deferred tax liabilities of approximately $810 million that were substantially comprised of book and tax basis differences related to our generation and mining property, plant, and equipment, partially offset by federal and state net operating loss (NOL) carryforwards. As of December 31, 2025, we assessed the need for a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. We have identified positive evidence in the form of cumulative income on an unadjusted basis over the preceding 12 quarters. We evaluated historical earnings, performed scheduling of the reversal of temporary differences, and considered other positive and negative evidence. In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by future taxable income, and thus no valuation allowance was required.

104
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2025, we had $3.8 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2031.

The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax assets of zero and net deferred tax liabilities $4 million at December 31, 2025 and 2024, respectively.

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 effective income tax rate. 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.

Liability for Uncertain Tax Positions

Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.

We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were immaterial for the years ended December 31, 2025, 2024 and 2023. The following table summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets for the years ended December 31, 2025, 2024 and 2023.
Year Ended December 31,
202520242023
(in millions)
Balance at beginning of period, excluding interest and penalties$4 $— $36 
Additions based on tax positions related to prior years— 4 — 
Reductions based on tax positions related to prior years— — — 
Reductions related to the lapse of the tax statute of limitations— — (35)
Settlements with taxing authorities— — (1)
Balance at end of period, excluding interest and penalties$4 $4 $— 

Vistra and its subsidiaries file income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject to examinations by the IRS and other taxing authorities. Uncertain tax positions totaled $4 million and $4 million as of December 31, 2025 and 2024, respectively. Of the amounts recorded as unrecognized tax benefits, an insignificant portion would impact our effective tax rate if recognized.

Tax Matters Agreement

On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties.

Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp.

We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions.

105
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off.

Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d) we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off.

7.PROPERTY, PLANT, AND EQUIPMENT

Our property, plant, and equipment consist of our power generation assets, related mining assets, land, information systems hardware, capitalized corporate office lease space and other leasehold improvements. The estimated remaining useful lives of our property, plant, and equipment ranges from 1 to 28 years. Land and construction work in progress are not depreciated.
December 31,
20252024
(in millions)
Power generation and structures and office and other equipment$25,084 $22,943 
Land637 603 
Construction work in progress1,917 1,060 
Finance lease right-of-use assets190 186 
Nuclear fuel2,036 1,843 
Property, plant, and equipment — gross
29,864 26,635 
Less accumulated depreciation(9,273)(8,020)
Less finance lease right-of-use assets accumulated amortization
(41)(33)
Less accumulated amortization of nuclear fuel
(704)(409)
Property, plant, and equipment — net$19,846 $18,173 

Depreciation and amortization of property, plant, and equipment (including the classification in the consolidated statements of operations) consisted of the following:
Property, Plant, and Equipment
Consolidated Statements of Operations
Year Ended December 31,
202520242023
(in millions)
Power generation and structures and office and other equipmentDepreciation and amortization$1,811 $1,662 $1,335 
Finance lease right-of-use assetsDepreciation and amortization9 8 9 
Nuclear fuelFuel, purchased power costs, and delivery fees$487 $387 $91 
Total property, plant, and equipment expense$2,307 $2,057 $1,435 

106
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Retirement of Generation Facilities

Below are our operating facilities that have an announced retirement date. Operating results for generation facilities with defined retirement dates are included in our Asset Closure segment in the calendar year following the year in which the retirement occurs. The Moss Landing 300 MW and Moss Landing 100 MW battery facilities were transferred to the Asset Closure segment during the first quarter of 2025 and the fourth quarter of 2025, respectively, as we do not plan to return those assets to operations. See Note 8 for additional information.
FacilityLocationISO/RTOFuel Type
Net Capacity (MW)
Expected Retirement Date (a)
Segment
BaldwinBaldwin, ILMISOCoal1,185By the end of 2027East
Coleto CreekGoliad, TXERCOTCoal650
By the end of 2027
Texas
KincaidKincaid, ILPJMCoal1,108By the end of 2027East
Miami FortNorth Bend, OHPJMCoal1,020
By the middle of 2028
East
NewtonNewton, ILMISOCoal615By the end of 2027East
Total4,578
____________
(a)Expected retirement dates my change if economic or other conditions dictate.

The Company intends to repower Coleto Creek and Miami Fort as gas-fueled facilities upon their retirements as coal-fueled facilities. We are currently evaluating the feasibility of converting the other coal-fueled facilities with expected retirement dates in 2027 to gas-fueled facilities.

Impairment of Long-Lived Assets

In the year ended December 31, 2025, we recognized impairment losses of approximately $155 million related to the Moss Landing 100 MW battery (see Note 8 for additional information) and $73 million related to development projects we have no plans to complete.

In the year ended December 31, 2023, we recognized an impairment loss of $49 million related to our Kincaid generation facility in Illinois as a result of a significant decrease in the projected operating margins of the facility, primarily driven by a decrease in projected power prices. The impairment is reported in our East segment and includes write-downs of property, plant, and equipment of $45 million, write-downs of inventory of $2 million, and write-downs of operating lease right-of-use assets of $2 million.

In determining the fair value of the impaired asset groups, we utilized the income approach described in ASC 820, Fair Value Measurement.

8.LOSS EVENTS AND INSURANCE RECOVERIES

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 for additional information).

107
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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. See Note 18 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. The initial insurance receivable asset related to expenses we believe were probable of recovery from property damage insurance was $425 million, recorded as offsets to the expenses incurred in other noncurrent assets in the consolidated balance sheets. See Insurance Recoveries 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.

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. During the year ended December 31, 2025, we recognized property damage insurance recoveries of $160 million, of which $40 million was recorded as an offset to operating costs incurred to restore the unit to service, and $120 million was recorded as a gain in other income, net in the consolidated statements of operations. During the year ended December 31, 2025, we recognized business interruption insurance proceeds of $47 million recorded in operating revenues. See Insurance Recoveries for additional information.

108
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Insurance Recoveries

The following table summarizes the expenses recorded, net of property damage insurance recoveries, related to the Moss Landing Incident and Martin Lake Incident during the year ended December 31, 2025.
Year Ended December 31, 2025
Moss Landing IncidentMartin Lake IncidentTotal
(in millions)
Write-off of net book value of facility to depreciation and amortization$400 $— $400 
Operating costs incurred to restore Martin Lake to service— 40 40 
Incurred and estimated cost of ASAOC activities to operating costs (a)102 — 102 
Total incident expense$502 $40 $542 
Property damage insurance receivable as of the beginning of the period (b)$— $— $— 
Recovery of incident expense recorded to insurance receivable 425 40 465 
Insurance recovery gain recorded in other income, net
— 120 120 
Insurance proceeds received(227)(140)(367)
Property damage insurance receivable as of the end of the period (b)$198 $20 $218 
Total incident expense, net of property damage insurance recoveries$77 $— $77 
____________
(a)Total estimated costs of ASAOC activities is expected to be approximately $110 million, of which $102 million was recorded in operating costs in the consolidated statements of operations. Amounts above exclude $8 million of estimated demolition and battery removal costs reclassified from the Moss Landing 300 ARO to other current liabilities during the three months ended March 31, 2025.
(b)Property damage insurance receivable is included in other noncurrent assets on the consolidated balance sheets.

The following table summarizes the business interruption insurance recoveries related to the Moss Landing Incident and Martin Lake Incident during the year ended December 31, 2025.
Year Ended December 31, 2025
Moss Landing IncidentMartin Lake IncidentTotal
(in millions)
Business interruption insurance proceeds realized (a)
$71 $47 $118 
____________
(a)Business interruption insurance proceeds are included in operating revenues in the consolidated statements of operations.

We expect to receive additional property damage and business interruption insurance proceeds related to the Martin Lake Incident and additional business interruption insurance proceeds related to the Moss Landing Incident which are not included in the property damage insurance receivable as of the year ended December 31, 2025. These additional proceeds will be recorded as income in the period they are realized.

109
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9.GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

As of December 31, 2025 and 2024, the carrying value of goodwill totaled $2.810 billion and $2.807 billion, respectively.

Retail SegmentTexas Segment
Retail Reporting Unit (a)Texas Generation Reporting Unit
Goodwill Pending Allocation
Total Goodwill
(in millions)
Balance at December 31, 2024
$2,461 $122 $224 $2,807 
Measurement period adjustment recorded in connection with the Energy Harbor Merger (b)
227 — (224)3 
Balance at December 31, 2025
$2,688 $122 $— $2,810 
____________
(a)Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight-line basis.
(b)Includes the allocation of goodwill attributable to the Energy Harbor acquisition to the retail reporting unit (see Note 2 for additional information).

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:
December 31, 2025December 31, 2024
Identifiable Intangible AssetGross
Carrying
Amount		Accumulated
Amortization		NetGross
Carrying
Amount		Accumulated
Amortization		Net
(in millions)
Retail customer relationships$2,173 $2,067 $106 $2,173 $1,977 $196 
Software and other technology-related assets656 365 291 601 293 308 
Retail and wholesale contracts369 295 74 503 353 150 
Long-term service agreements18 6 12 18 5 13 
Other identifiable intangible assets (a)628 17 611 218 13 205 
Total identifiable intangible assets subject to amortization$3,844 $2,750 1,094 $3,513 $2,641 872 
Retail trade names (not subject to amortization)1,341 1,341 
Total identifiable intangible assets$2,435 $2,213 
____________
(a)Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).

Identifiable intangible liabilities are comprised of the following:
Year Ended December 31,
Identifiable Intangible Liability20252024
(in millions)
Long-term service agreements
$100 $108 
Wholesale power and fuel purchase contracts
38 47 
Total identifiable intangible liabilities$138 $155 

110
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amortization of finite-lived identifiable intangible assets and liabilities (including the classification in the consolidated statements of operations) consisted of the following:
Identifiable Intangible Assets/LiabilitiesConsolidated Statements of OperationsRemaining useful lives of identifiable intangible assets at December 31,
2025 (weighted average in years)		Year Ended December 31,
202520242023
(in millions)
Retail customer relationshipsDepreciation and amortization1$90 $111 $98 
Software and other technology-related assetsDepreciation and amortization269 60 58 
Retail and wholesale contractsOperating revenues/Fuel, purchased power costs, and delivery fees3(9)(12)8 
Other identifiable intangible assets (a)Fuel, purchased power costs, and delivery fees/Depreciation and amortization4488 414 357 
Total intangible asset expense, net$638 $573 $521 
___________
(a)Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery fees in the consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.

The following is a description of the separately identifiable intangible assets recorded in fresh start reporting and in connection with purchase accounting from acquisitions.

•Retail customer relationship — Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.

•Retail and wholesale contracts — These intangible assets and liabilities represent the value of various acquired retail and wholesale contracts and fuel and transportation purchase contracts. The contracts were identified as either assets or liabilities based on the respective fair values utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The intangible assets or liabilities are amortized in relation to the economic terms of the related contracts.

•LTSA — Our acquired LTSA intangibles represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements and are amortized based on the expected usage of the service agreements over the contract terms. The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant, and equipment.

•Retail trade names — Our retail trade name intangible assets represent the fair value of our retail brands, including the trade names of TXU EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power, and U.S. Gas & Electric, and were determined to be indefinite-lived assets not subject to amortization. These intangible assets are evaluated for impairment at least annually in accordance with accounting guidance related to other indefinite-lived intangible assets. We have selected October 1 as our test date. Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest rates. On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2025.

111
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Estimated Amortization of Identifiable Intangible Assets

As of December 31, 2025, the estimated aggregate amortization expense of identifiable intangible assets, excluding environmental allowances, for each of the next five fiscal years is as shown below.
YearEstimated Amortization Expense
(in millions)
2026$178 
2027$83 
2028$63 
2029$45 
2030$24 

10.COLLATERAL FINANCING AGREEMENT WITH AFFILIATE

In 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed by the Company (the Trust) that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $450 million. The Trust is not consolidated by Vistra. The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S. Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S. dollars, the Eligible Assets). At the direction of Vistra Operations, the Eligible Assets held by the Trust can be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program.

Under the Facility Agreement, Vistra Operations has the right (Issuance Right), from time to time, to require the Trust to purchase from Vistra Operations up to $450 million aggregate principal amount of Vistra Operations' 7.233% Senior Secured Notes due 2028 (7.233% Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury Strips corresponding to the portion of the issuance right exercised at such time.

The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233% Senior Secured Notes to the holders of the P-Caps if its sole assets consist of 7.233% Senior Secured Notes that Vistra Operations is no longer entitled to repurchase.

Vistra Operations pays a facility fee (Facility Fee) to the Trust payable on each May 17 and November 17, commencing on November 17, 2023, to and including May 17, 2028 (each, a Distribution Date), and on certain other dates as provided in the Facility Agreement. The Facility Fee is generally calculated at a rate of 3.3608% per annum, applied to the maximum amount of 7.233% Senior Secured Notes that Vistra Operations could issue and sell to the Trust under the Facility Agreement as of the close of business on the business day immediately preceding the applicable Distribution Date.

As of December 31, 2025 and 2024, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $444 million and $435 million, respectively, and is reported in the consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate.

112
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11.DEBT, CREDIT FACILITIES, AND FINANCINGS

Debt, credit facilities and financing obligations on the consolidated balance sheets consisted of the following:
December 31,
20252024
(in millions)
Long-term debt, including amounts due currently:
Project-level debt$1,569 $1,064 
Vistra Operations debt15,627 15,405 
Long-term debt before unamortized premiums, discounts, and issuance costs17,196 16,469 
Unamortized premiums, discounts, and issuance costs(153)(171)
Long-term debt including amounts due currently
$17,043 $16,298 
Short-term borrowings
$1,800 $— 
Accounts receivable financing$1,225 $750 
Forward repurchase obligation$632 $1,335 

113
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-Term Debt

The Company's long-term debt obligations, including amounts due currently, consisted of the following:
December 31,
20252024
(in millions)
Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030$2,450 $2,475 
BCOP Credit Facility, Bridge Loans367 367 
BCOP Credit Facility, Construction / Term Loans505 — 
Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031697 697 
Vistra Operations Senior Secured Notes:
5.125% Senior Secured Notes, due May 13, 2025
— 744 
5.050% Senior Secured Notes, due December 30, 2026
500 500 
3.700% Senior Secured Notes, due January 30, 2027
800 800 
4.300% Senior Secured Notes, due October 15, 2028
750 — 
4.300% Senior Secured Notes, due July 15, 2029
800 800 
4.600% Senior Secured Notes, due October 15, 2030
500 — 
6.950% Senior Secured Notes, due October 15, 2033
1,050 1,050 
6.000% Senior Secured Notes, due April 15, 2034
500 500 
5.700% Senior Secured Notes, due December 30, 2034
750 750 
5.250% Senior Secured Notes, due October 15, 2035
750 — 
Total Vistra Operations Senior Secured Notes6,400 5,144 
Energy Harbor Revenue Bonds:
3.375% Revenue Bond, due August 1, 2029
100 100 
4.750% Revenue Bonds, due June 1, 2033 and July 1, 2033
285 285 
3.750% Revenue Bond, due October 1, 2047
46 46 
Total Energy Harbor Revenue Bonds431 431 
Vistra Operations Senior Unsecured Notes:
5.500% Senior Unsecured Notes, due September 1, 2026
— 1,000 
5.625% Senior Unsecured Notes, due February 15, 2027
1,300 1,300 
5.000% Senior Unsecured Notes, due July 31, 2027
1,300 1,300 
4.375% Senior Unsecured Notes, due May 1, 2029
1,250 1,250 
7.750% Senior Unsecured Notes, due October 15, 2031
1,450 1,450 
6.875% Senior Unsecured Notes, due April 15, 2032
1,000 1,000 
Total Vistra Operations Senior Unsecured Notes6,300 7,300 
Other:
Equipment Financing Agreements46 55 
Total other long-term debt46 55 
Unamortized debt premiums, discounts, and issuance costs(153)(171)
Total long-term debt including amounts due currently17,043 16,298 
Less amounts due currently(1,201)(880)
Total long-term debt less amounts due currently$15,842 $15,418 


114
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-Term Debt Maturities

Long-term debt maturities as of December 31, 2025 are as follows:
December 31, 2025
(in millions)
2026$1,201 
20273,435 
2028786 
20292,362 
20302,853 
Thereafter6,559 
Unamortized premiums, discounts, and debt issuance costs(153)
Total long-term debt, including amounts due currently$17,043 

Credit Facilities

Our credit facilities and related available capacity as of December 31, 2025 are presented below.
December 31, 2025
Credit FacilitiesMaturity DateFacility
Limit
Borrowings Outstanding
Letters of Credit OutstandingAvailable
Capacity
(in millions)
Vistra Operations debt:
Revolving Credit FacilityOctober 11, 2029$3,440 $380 $1,064 $1,996 
Term Loan B-3 FacilityDecember 20, 20302,450 2,450 — — 
Total Vistra Operations Credit Facilities$5,890 $2,830 $1,064 $1,996 
Vistra Operations Commodity-Linked FacilitySeptember 30, 20261,750 1,420 — 2 
Total Vistra Operations debt$7,640 $4,250 $1,064 $1,998 
Project-level debt:
Bridge Loans
January 30, 2026 (a) / December 3, 2026
367 367 — — 
Construction / Term Loans
(b)
505 505 — — 
BCOP Credit Facility872 872 — — 
Vistra Zero Term Loan B FacilityApril 30, 2031697 697 — — 
Total project-level debt$1,569 $1,569 $— $— 
Total credit facilities$9,209 $5,819 $1,064 $1,998 
____________
(a)In January 2026, Vistra repaid the $106 million Oak Hill Bridge Loan at maturity. See additional information in BCOP Project-level Credit Facilities discussion below.
(b)Maturity dates between December 3, 2026 and December 3, 2029. See additional information in BCOP Project-level Credit Facilities discussion below.

Vistra Operations Credit Facilities

As of December 31, 2025, the Vistra Operations Credit Facilities have aggregate commitments of up to $5.890 billion in senior secured, first-lien revolving credit commitments and outstanding term loans (Vistra Operations Credit Facilities). The Vistra Operations Credit Facilities consist of (i) revolving credit commitments (including aggregate revolving letter of credit commitments) of up to $3.440 billion (Revolving Credit Facility), and (ii) term loans of $2.450 billion (Term Loan B-3 Facility).

115
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revolving Credit Facility — The Revolving Credit Facility is used for general corporate purposes. Borrowings under the Revolving Credit Facility bear interest based the forward-looking term rate based on SOFR (Term SOFR) plus a spread that ranges from 1.25% to 2.00%. We pay fees on any undrawn amounts of the Revolving Credit Facility ranging from 17.5 basis points to 35.0 basis points. Letters of credit issued under the Revolving Credit Facility are subject to a fee that ranges from 1.25% to 2.00%. Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of December 31, 2025, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 17.5 and 27.0 basis points, respectively, and the applicable fee for the letters of credit issued under the Revolving Credit Facility was 1.725%. Borrowings under the Revolving Credit Facility are included in short-term borrowings in the consolidated balance sheets.

Term Loan B-3 Facility — The Term Loan B-3 Facility is used for general corporate purposes. Borrowings under the Term Loan B-3 Facility bear interest based on the applicable Term SOFR, plus a fixed spread of 1.75%. The weighted average interest rate, before taking into consideration interest rate swaps (see Note 13 for additional information) on outstanding borrowings of $2.450 billion, was 5.466% as of December 31, 2025. Cash borrowings under the Term Loan B-3 Facility are subject to required scheduled quarterly payments of $6.25 million. Amounts paid cannot be reborrowed.

Other Information — Obligations under the Vistra Operations Credit Facilities are secured by liens on substantially all of Vistra Operations' (and certain of its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Agreement. The Vistra Operations Credit Agreement includes collateral suspension provisions that become effective if Vistra Operations achieves unsecured investment-grade credit ratings from at least two ratings agencies and no term loans (as defined in the Vistra Operations Credit Agreement) remain outstanding (or the holders thereof agree to release their security interests). The collateral suspension provisions will remain in effect unless and until Vistra Operations ceases to maintain unsecured investment-grade ratings from at least two ratings agencies, at which time collateral reversion provisions would apply, subject to a 60-day grace period.

The Vistra Operations Credit Facilities also permit certain hedging agreements and cash management agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities, provided such agreements satisfy the applicable criteria set forth therein.

The Vistra Operations Credit Facilities contain customary affirmative and negative covenants applicable to Vistra Operations and its restricted subsidiaries, including affirmative covenants requiring the delivery of financial and other information to the administrative agent and restrictions on changes to lines of business. The negative covenants restrict Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Agreement. The Vistra Operations Credit Agreement also includes a springing financial covenant with respect to the Revolving Credit Facility that, when applicable, would require compliance with a consolidated first lien net leverage ratio (or, during a collateral suspension period, a consolidated total net leverage ratio). Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the existence of material unpaid (or unstayed) judgments against Vistra Operations and certain of its subsidiaries. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2025, Vistra Operations can distribute approximately $11.2 billion to Parent without the consent of any party. The amount available for distribution has been reduced by distributions made by Vistra Operations to Parent of approximately $1.625 billion, $1.705 billion, and $1.625 billion during the years ended December 31, 2025, 2024 and 2023, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to pay any taxes or general operating or corporate overhead expenses arising out of Parent's ownership or operation of Vistra Operations. As of December 31, 2025, all of the restricted net assets of Vistra Operations may be distributed to Parent.

116
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Vistra Operations Commodity-Linked Revolving Credit Facility

As of December 31, 2025, Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) totaled $1.75 billion of aggregate available commitments. We have the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility to $3.0 billion. In October 2025, Vistra Operations amended the Commodity-Linked Facility to, among other things, extend the maturity date to September 30, 2026. As of December 31, 2025, the borrowing base of $1.422 billion is lower than the facility limit which represents the aggregate commitments of $1.75 billion. Borrowings under the Commodity-Linked Facility are included in short-term borrowings in the consolidated balance sheets.

Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero. Vistra Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce outstanding borrowings to be less than or equal to the borrowing base. Vistra Operations intends to use any borrowings provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time to time and for other working capital and general corporate purposes.

Interest on the Commodity-Linked Facility is based on either the Term SOFR or a daily simple SOFR rate, plus (i) a spread that ranges from 1.25% to 2.00%, and (ii) sustainability pricing adjustments based on certain sustainability-linked targets and thresholds. The fee on any undrawn amounts with respect to the Commodity-Linked Facility ranges from 17.5 basis points to 35.0 basis points. As of December 31, 2025, the applicable interest rate margins for borrowings outstanding under the Commodity-Linked Facility was 1.725% and the fee on any undrawn amounts with respect to the Commodity-Linked Facility was 27.0 basis points. Interest and fees on the Commodity-Linked Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of December 31, 2025, the weighted average interest rate on outstanding borrowings under the Commodity-Linked Facility was 5.45%.

BCOP Project-level Credit Facilities

In December 2024, BCOP and its subsidiaries entered into the BCOP Credit Agreement to finance the development of the Baldwin and Coffeen solar generation and battery ESS facilities and the Oak Hill and Pulaski solar generation facilities located in Illinois and Texas. The BCOP Credit Agreement provides for (i) bridge loan commitments of $367 million for the Oak Hill and Pulaski projects (the Bridge Loans) and (ii) construction and term loan commitments of $528 million (the Construction/Term Loan Facility), together with debt service reserve letter of credit commitments of $29 million (the Debt Service Reserve and, collectively with the Bridge Loans and the Construction/Term Loan Facility, the BCOP Credit Facility).

As of December 31, 2025, outstanding Bridge Loans totaled $106 million for Oak Hill and $261 million for Pulaski, with scheduled maturities in November 2025 and December 2026, respectively, subject to the terms of the BCOP Credit Agreement. In October 2025, the maturity date of the $106 million Oak Hill Bridge Loans was extended to January 30, 2026. Interest on the Bridge Loans is payable in arrears at the applicable Term SOFR rate elected in the related borrowing notice plus a fixed margin of 1.625% per annum, and the weighted-average interest rate on outstanding Bridge Loan borrowings was 5.355% as of December 31, 2025. Repayment of the Bridge Loans is guaranteed by Vistra as the beneficiary of the underlying investment tax credits expected to be generated by the applicable projects. In January 2026, Vistra repaid the $106 million Oak Hill Bridge Loan at maturity.

The Construction/Term Loan Facility consists of (i) term loans supporting the Baldwin and Coffeen projects and (ii) construction loans used to fund the Oak Hill and Pulaski projects during their construction periods, which convert to term loans upon each project's achievement of commercial operation and satisfaction of the applicable term conversion conditions. Construction and term loan activity during 2025 included the following:

•Baldwin and Coffeen: In April 2025, BCOP funded $75 million and $45 million of term loans for the Baldwin and Coffeen projects, respectively, each of which will mature in December 2029. In addition, BCOP issued $7 million of letters of credit under the Debt Service Reserve facility to support these term loans.
•Oak Hill: In May 2025, BCOP funded $88 million of construction loans for the Oak Hill project with a scheduled maturity in November 2025. In October 2025, the Oak Hill project achieved commercial operation, and the construction loans automatically converted into a term loan maturing in December 2029.
117
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•Pulaski: In July, August, and December 2025, BCOP funded an aggregate of $297 million of construction loans for the Pulaski project. These construction loans mature in December 2026 and, subject to satisfaction of certain conditions, will convert into a term loan maturing in December 2029.

Interest on construction and term loans under the Construction/Term Loan Facility is payable in arrears at the applicable Term SOFR rate elected in the borrowing notice plus a fixed margin of 1.875% per annum for construction loans and 2.000% per annum for term loans. The weighted-average interest rate on outstanding construction and term loan borrowings was 5.821% as of December 31, 2025. Beginning on the applicable term funding or term conversion date, the term loans amortize over a 20-year period, with principal and interest payments funded from the cash flows generated by the underlying projects. Fees on issued debt service reserve letters of credit accrue at 2.000% per annum and are payable in arrears. Commitment fees on undrawn loan commitments and unissued letter of credit commitments are payable quarterly in arrears at a fixed percentage of the applicable loan margin.

BCOP's obligations under the BCOP Credit Agreement are guaranteed by subsidiaries of BCOP but are otherwise non-recourse to Vistra Operations and its other subsidiaries.

Vistra Zero Project-level Credit Agreement

In March 2024, Vistra Zero Operating entered into the Vistra Zero Credit Agreement. The Vistra Zero Credit Agreement provides for a senior secured term loan (Term Loan B Facility) of up to $700 million, which Vistra Zero Operating borrowed in its entirety in March 2024. Net proceeds of $690 million were used (i) to pay issuance costs and (ii) for working capital and general corporate purposes. Vistra Zero Operating's obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operating, but are otherwise non-recourse to Vistra Operations and its other subsidiaries.

Interest on the Term Loan B Facility is based on Term SOFR plus 2.00% per annum. Interest periods for Term SOFR loans are for one-, three-, or six-month periods with interest paid in arrears. The weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings of $697 million was 5.716% as of December 31, 2025.

The Vistra Zero Credit Agreement contains customary covenants and warranties which are generally consistent in scope with the Vistra Operations Credit Agreement, except that there is no financial maintenance covenant in the Vistra Zero Credit Agreement.

Vistra Zero Operating's obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operating but are otherwise non-recourse to Vistra Operations and its other subsidiaries.

Letter of Credit Facilities

Vistra Operations Secured Letter of Credit Facilities

Between August 2020 and December 2025, we entered into uncommitted standby letter of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities). The Secured LOC Facilities do not have stated expiration dates and are used for general corporate purposes. As of December 31, 2025, $1.332 billion of letters of credit were outstanding under the Secured LOC Facilities.

Vistra Operations Unsecured Alternative Letter of Credit Facilities

In March 2024, we entered into unsecured alternative letter of credit facilities (Alternative LOC Facilities) to be used for general corporate purposes. In October 2025, the Alternative LOC Facilities were amended to increase the commitment cap from $500 million to a total of $800 million. As of December 31, 2025, the total capacity was $760 million and $608 million of letters of credit were outstanding under the Alternative LOC Facilities. The commitments under the Alternative LOC Facilities terminate in December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities.

118
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Financial Covenants

The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and revolving letters of credit outstanding (excluding all undrawn revolving letters of credit and cash collateralized backstopped revolving letters of credit) exceed 35% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). In addition, each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). As of December 31, 2025, we were in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants.

Vistra Operations Senior Secured Notes

Vistra Operations issues and sells its senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Secured Notes). The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the Senior Secured Notes provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a first-priority security interest in the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities and contains certain covenants and restrictions consistent with the Vistra Operations Credit Facilities.

In January 2026, Vistra Operations issued $2.25 billion aggregate principal amount of senior secured notes, consisting of $1.0 billion aggregate principal amount of 4.700% senior secured notes due 2031 (4.700% Senior Secured Notes) and $1.250 billion aggregate principal amount of 5.350% senior secured notes due 2036 (5.350% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in arrears on January 31 and July 31 beginning July 31, 2026. Net proceeds totaling approximately $2.230 billion, together with cash on hand, will be used to (i) fund a portion of the consideration for the Cogentrix Transaction (see Note 2 for additional information), (ii) for general corporate purposes, including to repay existing indebtedness, and (iii) to pay fees and expenses related to the offering.

In October 2025, Vistra Operations issued $2.0 billion aggregate principal amount of senior secured notes, consisting of $750 million aggregate principal amount of 4.300% senior secured notes due 2028 (4.300% Senior Secured Notes), $500 million aggregate principal amount of 4.600% senior secured notes due 2030 (4.600% Senior Secured Notes) and $750 million aggregate principal amount of 5.250% senior secured notes due 2035 (5.250% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning April 15, 2026. Net proceeds totaling approximately $1.984 billion, together with cash on hand, will be used for (i) to support refinancing activities for outstanding indebtedness (see Vistra Operations Senior Unsecured Notes below), (ii) for general corporate purposes, including to fund a portion of the Lotus Acquisition (see Note 2 for additional information), and (iii) to pay fees and expenses related to the offering.

In May 2025, the $744 million outstanding principal amount of the 5.125% Senior Secured Notes due May 2025 was repaid at maturity.

Energy Harbor Revenue Bonds

Various governmental entities in Ohio and Pennsylvania have issued multiple tranches of revenue bonds for the benefit of Energy Harbor Generation LLC (EHG) or Energy Harbor Nuclear Generation LLC (EHNG); (collectively, the EH entities), in an aggregate principal amount of $431 million. The relevant EH entity is obligated to provide contractual payments to the applicable issuer of the revenue bonds to service the principal and interest on the revenue bonds, the payment of which is indirectly secured by all or substantially all of the assets of the EH entities under various mortgage bonds issued by the EH entities. In the event of a default by the EH entities of their contractual obligation to pay principal and interest in respect of the revenue bonds, the trustee of the revenue bonds would be able to call the mortgage bonds due and, if unpaid, foreclose on the assets securing the mortgage bonds. The obligations of the EH entities in respect of the revenue bonds and related mortgage bonds are guaranteed on an unsecured basis by Energy Harbor and Vistra.

119
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Vistra Operations Senior Unsecured Notes

Vistra Operations issues and sells its senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Unsecured Notes). The indentures (as may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) governing the Senior Unsecured Notes provide for the full and unconditional guarantee by the Guarantor Subsidiaries. The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

In October 2025, Vistra Operations used a portion of the proceeds from the October 2025 issuance of Vistra Operations Senior Secured Notes discussed above to redeem the $1.0 billion outstanding principal amount of 5.500% Senior Unsecured Notes due 2026.

Other Debt Activity

As part of the Lotus Acquisition in October 2025, Vistra assumed a senior secured credit facility with an existing $803 million term loan due August 1, 2030. In November 2025, we repaid the term loan for $808 million including accrued interest and fees.

Accounts Receivable Financing

Accounts Receivable Securitization Program

TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). In June 2025, the Receivables Facility was amended to add Dynegy Energy Services Mid-Atlantic, LLC. In July 2025, the Receivables Facility was amended to increase the purchase limit from $1.0 billion to $1.1 billion and to extend the term of the Receivables Facility to July 2026.

In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Dynegy Energy Services Mid-Atlantic, LLC., Ambit Texas, Value Based Brands, Energy Harbor LLC and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limit described above to fund its acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the performance of the obligations of the Originators and TXU Energy, as the servicer, under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as accounts receivables financing in the consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in the consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable.

As of December 31, 2025, outstanding borrowings under the Receivables Facility totaled $1.1 billion and were supported by $1.538 billion of RecCo gross receivables. As of December 31, 2024, there were $750 million in outstanding borrowings under the Receivables Facility.

120
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Repurchase Facility

TXU Energy and the other Originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2025, the Repurchase Facility was renewed until July 2026 while maintaining the facility size of $125 million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and represents a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Repo Transaction). Each Repo Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.

TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the Receivables Facility.

As of December 31, 2025, outstanding borrowings under the Repurchase Facility totaled $125 million. There were no outstanding borrowings under the Repurchase Facility as of December 31, 2024.

Forward Repurchase Obligation

In accordance with the amended UPAs, on December 31, 2024, Vistra closed the acquisition of the Vistra Vision minority interest from Avenue and Nuveen. Vistra paid Avenue for the purchase of their minority interest in Vistra Vision in full upon closing and paid Nuveen an initial payment at closing, with the remaining payments to Nuveen to be paid in multiple installments through December 31, 2026. Vistra Vision Holdings' remaining future payments to Nuveen are guaranteed by Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes. In June 2025 and December 2025, Vistra made scheduled installment payments to reduce the forward repurchase obligation by $781 million, including $703 million of principal and $78 million of interest. Principal and interest payments remaining due to Nuveen are as follows:
December 31, 2025
(in millions)
2026669 
Thereafter— 
Total scheduled payments under the UPAs$669 

The present value of the remaining payment obligations to Nuveen discounted at 6% was $632 million at December 31, 2025 and is included in forward repurchase obligation due currently on the consolidated balance sheet. The amount discounted at 6% was $1.335 billion at December 31, 2024, and is included in forward repurchase obligation due currently and forward repurchase obligation, less amounts due currently in the consolidated balance sheets.

Interest Expense and Related Charges
Year Ended December 31,
202520242023
(in millions)
Interest expense$1,107 $936 $654 
Unrealized mark-to-market net (gains) losses on interest rate swaps67 (53)36 
Amortization of debt issuance costs, discounts, and premiums46 34 26 
Debt extinguishment gain— (6)(3)
Capitalized interest(125)(77)(37)
Other84 66 64 
Total interest expense and related charges$1,179 $900 $740 

121
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 13, was 5.18%, 5.23%, and 5.69% as of December 31, 2025, 2024 and 2023, respectively.

12.LEASES

Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease terms for 1 to 41 years. Our leases include options to renew up to 15 years. Certain leases also contain options to terminate the lease.

Lease Cost

The following table presents costs related to lease activities:
Year Ended December 31,
202520242023
(in millions)
Operating lease cost$16 $17 $12 
Finance lease:
Finance lease right-of-use asset amortization9 8 10 
Interest on lease liabilities11 11 11 
Total finance lease cost20 19 21 
Variable lease cost (a)24 29 37 
Short-term lease cost22 56 44 
Total lease cost$82 $121 $114 
____________
(a)Represents coal stockpile management services, common area maintenance services, and rail car payments based on the number of rail cars used.

Balance Sheet Information

The following table presents lease related balance sheet information:
December 31,
20252024
(in millions)
Lease assets:
Operating lease right-of-use assets (reported in other noncurrent assets in the consolidated balance sheets)$98 $106 
Finance lease right-of-use assets, net of accumulated amortization (reported in property, plant, and equipment in the consolidated balance sheets)149 $153 
Total lease right-of-use assets$247 $259 
Current lease liabilities (reported in other current liabilities in the consolidated balance sheets):
Operating lease liabilities$13 $13 
Finance lease liabilities4 9 
Total current lease liabilities17 22 
Noncurrent lease liabilities (reported in other noncurrent liabilities and deferred credits in the consolidated balance sheets):
Operating lease liabilities92 98 
Finance lease liabilities218 218 
Total noncurrent lease liabilities310 316 
Total lease liabilities$327 $338 

122
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Cash Flow Information

The following table presents lease related cash flows and other information:
Year Ended December 31,
202520242023
(in millions)
Non-cash disclosure upon commencement of new lease:
Right-of-use assets obtained in exchange for new operating lease liabilities$24 $68 $3 
Right-of-use assets obtained in exchange for new finance lease liabilities4 — — 
Non-cash disclosure upon modification of existing lease:
Modification of operating lease right-of-use assets$— $1 $7 
Modification of finance lease right-of-use assets— — (1)

Weighted Average Remaining Lease Term

The following table presents weighted average remaining lease term information:
December 31,
20252024
Weighted average remaining lease term:
Operating lease24.2 years23.8 years
Finance lease23.1 years23.7 years
Weighted average discount rate:
Operating lease7.63%7.85 %
Finance lease4.84%4.82 %

Maturity of Lease Liabilities

The following table presents maturity of lease liabilities:
Operating LeaseFinance LeaseTotal Lease
(in millions)
2026$18 $15 $33 
202715 14 29 
202810 15 25 
20298 13 21 
20308 14 22 
Thereafter191 327 518 
Total lease payments250 398 648 
Less: Imputed interest(145)(176)(321)
Present value of lease liabilities$105 $222 $327 

13.DERIVATIVES

We utilize derivative instruments, such as options, swaps, futures, and forward contracts to manage our exposure to commodity price and interest rate volatility. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, fuel oil and natural gas producers, local distribution companies, and energy marketing companies.

123
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Commodity Derivatives

We utilize financial natural gas and financial and physical electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets. Financial transmission rights and congestion revenue rights are derivative instruments we utilize to hedge electricity price differences between settlement points within regions. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in operating revenues.

We utilize physical natural gas, coal, emissions, and renewable energy certificate derivatives primarily to hedge future purchased power costs of our retail operations or fuel costs of our generation assets. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in fuel, purchased power costs, and delivery fees.

Our Retail segment procures power from our generation segments to serve future load obligations. In locations and periods where our load service activities do not naturally offset existing generation portfolio risks, remaining commodity price exposure is managed through portfolio hedging activities.

Interest Rate Swaps

Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in interest expense and related charges.

As of December 31, 2025, Vistra has entered into the following interest rate swaps:
Notional AmountExpiration Date
Rate Range (d)
(in millions, except percentages)
Swapped to fixed (a)$3,000July 20262.89 %-2.97%
Swapped to variable (a)$700July 20261.44 %-1.49%
Swapped to fixed (b)$2,300December 20303.20 %-3.76%
Swapped to fixed (c)
$416
March, July and October 2045
3.95 %-4.09%
____________
(a)The $700 million of pay variable rate and receive fixed rate swaps match the terms of a portion of the $3.0 billion pay fixed rate and receive variable rate swaps. These matched swaps will settle over time and effectively offset the hedged position. These offsetting swaps expiring in July 2026 hedge our exposure on $2.3 billion of variable rate debt through July 2026.
(b)Effective from July 2026 through December 2030. These swaps will hedge our exposure on $2.3 billion of floating rate debt from August 2026 through December 2030.
(c)In March 2025, May 2025, and July 2025, BCOP entered into interest rate swaps with notional amounts of approximately $108 million, $70 million, and $238 million, respectively. These swaps are effective as of April 2025, October 2025, and October 2026, and will expire in March 2045, October 2045 and July 2045, respectively. These swaps are intended to hedge BCOP's exposure on approximately $416 million of floating rate Construction/Term Loan Facility commitments issued under the BCOP Credit Agreement. (see Note 11 for additional information).
(d)The rate ranges reflect the fixed leg of each swap at the applicable Term SOFR rate.

124
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Effect of Derivative Instruments on the Consolidated Balance Sheets

We maintain standardized master netting agreements with certain counterparties that allow for the right to offset accounts payable, accounts receivable, and cash collateral paid in order to reduce credit exposure. The following tables reconcile our gross derivative assets and liabilities as reported in the consolidated balance sheets to the net value on a contract basis, after taking into consideration netting arrangements with counterparties and cash collateral recorded.
December 31, 2025
Derivative Contract AssetsDerivative Contract Liabilities
Commodity ContractsInterest Rate SwapsCommodity ContractsInterest Rate SwapsTotal
(in millions)
Current assets$2,778 $10 $5 $— $2,793 
Noncurrent assets396 8 1 — 405 
Current liabilities— (1)(4,038)(10)(4,049)
Noncurrent liabilities(2)— (1,716)(11)(1,729)
Net assets (liabilities)$3,172 $17 $(5,748)$(21)$(2,580)
Offsetting instruments (a)$(2,622)$(10)$2,622 $10 — 
Financial collateral (received) pledged (b)$(7)$— $891 $— 884 
Net amounts$543 $7 $(2,235)$(11)$(1,696)
December 31, 2024
Derivative Contract AssetsDerivative Contract Liabilities
Commodity ContractsInterest Rate SwapsCommodity ContractsInterest Rate SwapsTotal
(in millions)
Current assets$2,551 $34 $2 $— $2,587 
Noncurrent assets677 62 1 — 740 
Current liabilities— — (3,333)(18)(3,351)
Noncurrent liabilities(2)— (1,356)(9)(1,367)
Net assets (liabilities)$3,226 $96 $(4,686)$(27)$(1,391)
Offsetting instruments (a)$(2,532)$(28)$2,532 $28 — 
Financial collateral (received) pledged (b)$(50)$— $233 $— 183 
Net amounts$644 $68 $(1,921)$1 $(1,208)
____________
(a)Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b)Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements.

125
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Effect of Derivative Instruments in the Consolidated Statements of Operations

The following table summarizes the location and amount of unrealized gains and losses from our derivative instruments recorded in the consolidated statements of operations for the periods presented.
Year Ended December 31,
Derivative (consolidated statements of operations presentation)202520242023
(in millions)
Reversals of previously recognized unrealized (gain) loss on derivative instruments:
Commodity contracts unrealized (gain) loss in operating revenues (a)$1,045 $1,140 $1,472 
Commodity contracts unrealized (gain) loss in fuel, purchased power costs, and delivery fees (a)(75)73 171 
Interest rate swaps unrealized (gain) loss in interest expense and related charges(15)(41)(78)
Total reversals of previously recognized unrealized (gain) loss on derivative instruments$955 $1,172 $1,565 
Unrealized net gain (loss) from changes in fair value on derivative instruments:
Commodity contracts unrealized gain (loss) in operating revenues$(1,811)$(127)$(758)
Commodity contracts unrealized gain (loss) in fuel, purchased power costs, and delivery fees33 69 (395)
Interest rate swaps unrealized gain (loss) in interest expense and related charges(52)94 42 
Total unrealized net gain (loss) from change in fair value on derivative instruments$(1,830)$36 $(1,111)
Net unrealized gain (loss) on derivative instruments$(875)$1,208 $454 
____________
(a)Excludes the realized effects of changes in fair value in the month the position settled, amounts related to positions entered into and settled in the same month, and physical retail and wholesale contracts accounted for as derivatives that did not financially settle but were realized at the contract's notional and price. The realized effects of these items are included in operating revenues and fuel, purchased power costs, and delivery fees.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes by commodity, excluding our NPNS derivatives that are not recorded at fair value:
December 31, 2025December 31, 2024
Derivative typeNotional VolumeUnit of Measure
Natural gas3,742 4,568 Million MMBtu
Electricity996,777 796,982 GWh
Financial transmission rights / Congestion revenue rights249,400 248,742 GWh
Coal22 27 Million U.S. tons
Fuel oil8 2 Million gallons
Emissions13 28 Million U.S. tons
Renewable energy certificates31 31 Million certificates
Interest rate swaps – variable/fixed$5,716 $5,300 Million U.S. dollars
Interest rate swaps - fixed/variable$700 $700 Million U.S. dollars

126
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Credit Risk-Related Contingent Features of Derivatives

Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements may require the posting of additional collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:
December 31,
20252024
(in millions)
Fair value of derivative contract liabilities (a)$(1,822)$(1,587)
Offsetting fair value under netting arrangements (b)528 724 
Cash collateral and letters of credit331 471 
Liquidity exposure$(963)$(392)
____________
(a)Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).
(b)Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.

Concentrations of Credit Risk Related to Derivatives

We have concentrations of credit risk with the counterparties to our derivative contracts that increase the risk that a default by any of our counterparties could have a material effect on our financial condition, results of operations and liquidity. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation procedures including, but not limited to, (i) requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our counterparties that allow for netting of positive and negative exposures, and (iii) credit enhancements (such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits) that are required in the event of a material downgrade in their credit rating.
December 31, 2025
(in millions, except percentages)
Credit risk exposure to derivative contract counterparties:
Gross exposure$3,777 
Net exposure (a)$807 
Largest net exposure from any single counterparty (a)$331 
Percent of credit risk exposure to derivative contract counterparties related to banking and financial sector:
Gross exposure72 %
Net exposure (a)10 %
____________
(a)Exposure after taking into effect netting arrangements, setoff provisions, and collateral.

127
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14.FAIR VALUE MEASUREMENTS

Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own market assumptions. We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy as defined by GAAP:

•Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date.

•Level 2 valuations use over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals.

•Level 3 valuations use unobservable inputs for the asset or liability, typically reflecting our estimate of assumptions that market participants would use in pricing the asset or liability. The fair value is therefore determined using model-based techniques, including discounted cash flow models.

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
December 31, 2025December 31, 2024
Level
1		Level
2
Level
3
Reclass (a)TotalLevel
1		Level
2
Level
3
Reclass (a)Total
(in millions)
Assets:
Commodity contracts (b)$2,162 $437 $573 $8 $3,180 $1,923 $462 $841 $5 $3,231 
Interest rate swaps (b)— 17 — 1 18 — 96 — — 96 
NDTs – equity securities (c)(d)1,761 — — 1,761 1,560 — — 1,560 
NDTs – debt securities (c)(e)117 1,971 — 2,088 83 1,976 — 2,059 
Sub-total$4,040 $2,425 $573 $9 7,047 $3,566 $2,534 $841 $5 6,946 
Assets measured at net asset value (f):
NDTs – equity securities (c)(d)(f)806 821 
NDTs – debt securities (c)(e)(f)329 — 
NDTs - other investments (c)(f)28 — 
Total assets$8,210 $7,767 
Liabilities:
Commodity contracts (b)$3,060 $846 $1,842 $8 $5,756 $2,118 $975 $1,593 $5 $4,691 
Interest rate swaps (b)— 21 — 1 22 — 27 — — 27 
Total liabilities$3,060 $867 $1,842 $9 $5,778 $2,118 $1,002 $1,593 $5 $4,718 
____________
(a)Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability position. This reclassification represents the adjustment needed to reconcile to the gross amounts presented in the consolidated balance sheets.
(b)See Note 13 for additional information.
128
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(c)NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in Investments in the consolidated balance sheets. There were no significant concentrations of credit risk from an individual counterparty or groups of counterparties in our NDT portfolio as of December 31, 2025.
(d)The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 and Russell 3000 Indices for U.S. equity investments and the MSCI EAFE and MSCI All Country World ex-US Indices for non-U.S. equity investments.
(e)The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt securities are weighted with government and investment grade corporate bonds. Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 4.02% and 3.99% as of December 31, 2025 and 2024, respectively, and an average maturity of eight years and seven years as of December 31, 2025 and 2024, respectively. NDT debt securities held as of December 31, 2025 mature as follows: $848 million in one to five years, $1.114 billion in five to 10 years and $455 million after 10 years.
(f)Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair values and therefore are not classified in the fair value hierarchy. This amount is presented to permit reconciliation of this table to the amounts presented in the consolidated balance sheets.

The following tables present the fair value of Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of December 31, 2025 and 2024:
December 31, 2025
Fair Value
Contract Type (a)AssetsLiabilitiesTotal, NetValuation TechniqueSignificant Unobservable InputRange (b)Average (b)
(in millions)
Electricity purchases and sales$269 $(1,607)$(1,338)Income ApproachHourly price curve shape (c)$— to$95 $48 
MWh
Illiquid delivery periods for hub power prices (d)$25 to$135 $80 
MWh
Market Heat Rates (d)$25 to$130 $78 
MWh
Options— (177)(177)Option Pricing ModelNatural gas to power correlation (e)15 %to100 %58 %
Power and natural gas volatility (e)5 %to1,120 %563 %
Financial transmission rights/Congestion revenue rights277 (34)243 Market Approach (f)Illiquid price differences between settlement points (g)$(12)to$25 $7 
MWh
Natural gas16 (24)(8)Income ApproachNatural gas basis (h)$(2)to$14 $6 
MMBtu
Illiquid delivery periods (i)$3 to$5 $4 
MMBtu
Other (j)11 — 11 
Total$573 $(1,842)$(1,269)

129
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2024
Fair Value
Contract Type (a)AssetsLiabilitiesTotal, NetValuation TechniqueSignificant Unobservable InputRange (b)Average (b)
(in millions)
Electricity purchases and sales$606 $(1,399)$(793)Income ApproachHourly price curve shape (c)$— to$95 $48 
MWh
Illiquid delivery periods for hub power prices and Heat Rates (d)$25 to$140 $83 
MWh
Market Heat Rates (d)
$30 $150 $90 
MWh
Options6 (139)(133)Option Pricing ModelNatural gas to power correlation (e)10 %to100 %55 %
Power and natural gas volatility (e)5 %to710 %358 %
Financial transmission rights/Congestion revenue rights190 (25)165 Market Approach (f)Illiquid price differences between settlement points (g)$(35)to$20 $(8)
MWh
Natural gas29 (30)(1)Income ApproachNatural gas basis (h)$— to$10 $5 
MMBtu
Illiquid delivery periods (i)$— to$5 $2 
MMBtu
Other (j)10 — 10 
Total$841 $(1,593)$(752)
____________
(a)(i) Electricity purchase and sales contracts include power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO, and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO, and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts.
(b)The range of the inputs may be influenced by factors such as time of day, delivery period, season, and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount.
(c)Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices.
(d)Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability.
(e)Primarily based on the historical forward correlation and volatility within ERCOT and PJM.
(f)While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid.
(g)Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
(h)Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices.
(i)Primarily based on the historical forward natural gas fixed prices.
(j)Other includes contracts for coal and environmental allowances.

130
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the changes in fair value of Level 3 assets and liabilities:
Year Ended December 31,
202520242023
(in millions)
Net liability balance at beginning of period$(752)$(1,044)$(1,219)
Total unrealized valuation gains (losses)(548)(175)(765)
Purchases, issuances and settlements (a):
Purchases313 266 222 
Issuances(25)(26)(30)
Settlements(147)137 136 
Transfers into Level 3 (b)(8)(15)(48)
Transfers out of Level 3 (b)308 118 660 
Net liabilities assumed in connection with acquisitions(410)(13)— 
Net change(517)292 175 
Net liability balance at end of period$(1,269)$(752)$(1,044)
Unrealized valuation losses relating to instruments held at end of period$(555)$(416)$(676)
____________
(a)Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.
(b)Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the year ended December 31, 2025, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power derivatives where forward pricing inputs have become observable. For the year ended December 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and natural gas derivatives where forward pricing inputs have become observable.

Assets and Liabilities Recorded on a Non-Recurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventories, assets acquired and liabilities assumed in business combinations, goodwill and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale.

The Energy Harbor Merger and the Lotus Acquisition were accounted for under the acquisition method which requires all assets acquired and liabilities assumed in the acquisition be recorded at fair value at the acquisition date. See Note 2 for additional information.

Fair Value of Debt
December 31, 2025December 31, 2024
InstrumentFair Value HierarchyCarrying AmountFair
Value		Carrying AmountFair
Value
(in millions)
Long-term debt under the Vistra Operations Credit FacilitiesLevel 2$2,417 $2,459 $2,435 $2,478 
BCOP Credit FacilityLevel 3859 872 344 367 
Vistra Zero Term Loan B FacilityLevel 2687 688 685 697 
Vistra Operations Senior NotesLevel 212,620 12,955 12,366 12,428 
Energy Harbor Revenue BondsLevel 2416 433 414 431 
Equipment Financing AgreementsLevel 345 45 54 53 
Forward Repurchase ObligationLevel 3632 632 1,335 1,335 

131
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We determine fair value in accordance with accounting standards. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.

15.ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations (ARO) primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs. AROs are based on legal obligations associated with enacted law, regulatory, or contractual retirement requirements for which decommissioning timing and cost estimates are reasonably estimable.

The following table summarizes the changes to our current and noncurrent ARO liabilities for the years ended December 31, 2025 and 2024:
Nuclear Plant DecommissioningLand Reclamation, Coal Ash and OtherTotal
(in millions)
Liability at December 31, 2023
$1,742 $796 $2,538 
Additions:
Accretion (a)130 40 170 
Adjustment for change in estimates (b)— 90 90 
Adjustment for obligations assumed through acquisition
1,368 — 1,368 
Reductions:
Payments— (88)(88)
Liability at December 31, 2024
3,240 838 4,078 
Additions:
Accretion (a)154 40 194 
Adjustment for change in estimates (b)(20)47 27 
Adjustment for obligations assumed through acquisitions— 13 13 
Reductions:
Payments— (96)(96)
Liability at December 31, 2025
3,374 842 4,216 
Less amounts due currently— (181)(181)
Noncurrent liability at December 31, 2025
$3,374 $661 $4,035 
____________
(a)For the years ended December 31, 2025 and 2024, nuclear plant decommissioning accretion includes $94 million and $74 million, respectively, of accretion expense recognized in operating costs in the consolidated statements of operations and $60 million and $56 million, respectively, reflected as a change in regulatory liability in the consolidated balance sheets.
(b)There is a corresponding non-cash change in property, plant, and equipment related to land, reclamation, coal ash, and other ARO adjustments of $66 million and $52 million for the years ended December 31, 2025 and 2024, respectively.

For the next five years, Vistra is projected to spend approximately $561 million (on a nominal basis) to achieve its mining reclamation and other coal ash remediation objectives.

Nuclear Decommissioning AROs

AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and the Beaver Valley, Perry, and Davis-Besse plants in PJM (the PJM nuclear facilities). To estimate our nuclear decommissioning obligations we use a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates.

132
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2025 and 2024, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $1.838 billion and $1.797 billion, respectively, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.589 billion and $2.249 billion, respectively. As of December 31, 2025 and 2024, the difference between the carrying value of the ARO and the NDT represents a regulatory liability of $751 million and $452 million, respectively, recorded to the consolidated balance sheets in other noncurrent liabilities and deferred credits since any excess funds in the NDT after decommissioning our Comanche Peak plant would be refunded to Oncor.

The carrying value of our ARO for our PJM nuclear facilities was recorded at fair value on the Merger Date. ARO accretion expense attributable to the PJM nuclear facilities is reflected in operating costs in the consolidated statements of operations. ARO estimates for the PJM nuclear facilities will be evaluated on an individual unit basis at least every five years unless triggering events warrant a more frequent review. Any changes in ARO estimates are recorded as an increase or decrease in ARO liability along with a corresponding change to asset retirement cost asset within property, plant, and equipment in the consolidated balance sheets; however, if the ARO estimate decreases by more than the remaining ARO asset, the balance of the change is recorded as a reduction to operating costs in the consolidated statement of operations.

16.PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS

Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries. Oncor is a participant in the Retirement Plan. Effective January 1, 2018, Vistra entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra. As Vistra accounts for its interests in the Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension benefit information presented below. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations. Since 2012, the Retirement Plan has been closed to new participants and the only participants who remain in the Retirement Plan are employees who were active prior to 2012, including retired collective bargaining unit employees. Accordingly, ongoing expenses associated with the Retirement plan are immaterial, including expenses associated with pensions plans acquired from Dynegy and Energy Harbor.

Vistra and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service.

Pension and OPEB Costs

The following table summarizes the total benefit costs of our pension and OPEB plans for the years ended December 31, 2025, 2024 and 2023. The individual components of benefit costs, including service cost, interest cost, expected return on assets and the net amortization of unrecognized amounts from accumulated other comprehensive income were immaterial.
Year Ended December 31,
202520242023
(in millions)
Pension costs$6 $9 $9 
OPEB costs4 5 5 
Total benefit costs recognized as expense$10 $14 $14 

133
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Market-Related Value of Assets Held in Pension Benefit Trusts

We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

Detailed Information Regarding Pension Plans and OPEB Benefits

The following information is based on a December 31, 2025, 2024 and 2023 measurement dates:
Retirement PlanOPEB Plans
Year Ended December 31,Year Ended December 31,
202520242023202520242023
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate5.39 %5.63 %4.97 %5.36 %5.62 %4.98 %
Expected rate of compensation increase (Vistra Plan)3.50 %3.50 %3.64 %
Expected rate of compensation increase (Dynegy Plan)4.68 %4.46 %
Interest crediting rate for cash balance plans4.50 %3.75 %3.50 %

Retirement PlanOPEB Plans
Year Ended December 31,Year Ended December 31,
2025202420252024
(in millions, except percentages)
Change in Pension and Postretirement Benefit Obligations:
Projected benefit obligation at beginning of period$409 $425 $99 $108 
Acquisitions— 23 — — 
Service cost2 2 — 1 
Interest cost22 21 5 5 
Participant contributions— — 3 3 
Actuarial (gain) loss13 (24)3 (7)
Benefits paid(33)(38)(12)(11)
Projected benefit obligation at end of year$413 $409 $98 $99 
Accumulated benefit obligation at end of year$412 $408 $— $— 
Change in Plan Assets:
Fair value of assets at beginning of period$285 $285 $10 $12 
Acquisitions— 18 — — 
Employer contributions29 19 8 8 
Participant contributions— — 3 2 
Actual gain on assets31 1 1 1 
Transfers— — — (2)
Benefits paid(33)(38)(12)(11)
Fair value of assets at end of year$312 $285 $10 $10 
Funded Status:
Projected benefit obligation$(413)$(409)$(98)$(99)
Fair value of assets312 285 10 10 
Funded status at end of year$(101)$(124)$(88)$(89)
134
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Retirement PlanOPEB Plans
Year Ended December 31,Year Ended December 31,
2025202420252024
Amounts Recognized in the Balance Sheet Consist of:
Investments$1 $1 $2 $2 
Other current liabilities— — (8)(8)
Other noncurrent liabilities(102)(125)(82)(83)
Net liability recognized$(101)$(124)$(88)$(89)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net actuarial gain$(4)$(5)$(19)$(22)
Prior services cost— — 1 1 
Net actuarial gain and prior service cost$(4)$(5)$(18)$(21)

Fair Value Measurement of Pension and OPEB Plan Assets

Retirement Plan

As of December 31, 2025 and 2024, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following:
December 31,
20252024
(in millions)
Asset Category:
Cash commingled trusts$8 $6 
Equity securities:
Global equities95 86 
Fixed income securities:
Corporate bonds (a)79 79 
Government bonds55 42 
Other (b)29 28 
Real estate29 27 
Hedge funds17 17 
Total assets measured at net asset value$312 $285 
___________
(a)Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.
(b)Consists primarily of high-yield bonds, emerging market debt, bank loans, securitized bonds and private investment grade fixed income.

OPEB Plans

As of December 31, 2025 and 2024, the Vistra OPEB plan assets measured at fair value totaled $10 million and $10 million, respectively. At December 31, 2025 and 2024, assets consisted of $6 million and $7 million, respectively, of commingled funds valued at net asset value and $4 million and $3 million, respectively, of municipal bond, short- and medium-duration bond, and cash equivalent mutual funds classified as Level 1.

135
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO) in Excess of Plan Assets

The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets.
December 31,
20252024
(in millions)
Pension Plans with PBO and ABO in Excess of Plan Assets:
Projected benefit obligations$413 $409 
Accumulated benefit obligation$412 $408 
Plan assets$312 $285 

Retirement Plan Investment Strategy and Asset Allocations

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities, and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets. Real estate, hedge funds, and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential.

The target asset allocation ranges of pension plan investments by asset category are as follows:
Retirement Plan
Target Allocation Ranges
Asset Category:Vistra PlanDynegy PlanEnergy Harbor Plan
Fixed income securities50 %-70%40 %-50%52 %-72%
Global equity securities20 %-28%28 %-38%22 %-30%
Real estate2 %-6%4 %-8%4 %-8%
Credit strategies2 %-6%4 %-8%3 %-7%
Hedge funds2 %-6%4 %-8%1 %-2%
Infrastructure funds2 %-6%4 %-8%

Retirement Plan Expected Long-Term Rate of Return on Assets Assumption

The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.
Retirement Plan
Expected Long-Term Rate of Return
Asset Class:Vistra PlanDynegy PlanEnergy Harbor Plan
Fixed income securities5.6 %5.2 %5.3 %
Global equity securities6.6 %6.6 %6.6 %
Real estate6.0 %6.0 %6.0 %
Credit strategies6.9 %6.9 %6.9 %
Hedge funds6.9 %6.9 %6.9 %
Infrastructure funds8.0 %8.0 %
Weighted average6.1 %6.0 %5.8 %

136
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Benefit Plan Assumed Health Care Cost Trend Rates

The following tables provide information regarding the assumed health care cost trend rates.
December 31,
20252024
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Health care cost trend rate assumed for next year7.00 %7.00 %
Rate to which the cost trend is expected to decline (the ultimate trend rate)4.50 %4.50 %
Year that the rate reaches the ultimate trend rate20352034
Assumed Health Care Cost Trend Rates-Medicare Eligible:
Health care cost trend rate assumed for next year (Vistra Plan)10.00 %15.70 %
Health care cost trend rate assumed for next year (Split-Participant Plan)9.90 %13.80 %
Rate to which the cost trend is expected to decline (the ultimate trend rate)4.50 %4.50 %
Year that the rate reaches the ultimate trend rate20352034

Significant Concentrations of Risk

The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.

Assumed Discount Rate

We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2025 consisted of 542 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings.

Contributions

Contributions to the Retirement Plan for the years ended December 31, 2025, 2024 and 2023 totaled $29 million, $19 million, and zero, respectively, and contributions in 2026 are expected to total $13 million. OPEB plan funding for each of the years ended December 31, 2025, 2024 and 2023 totaled $8 million, $8 million, and $9 million, respectively, and funding in 2026 is expected to total $8 million.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:
202620272028202920302031-2035
(in millions)
Pension benefits$35 $43 $32 $32 $32 $148 
OPEB$9 $9 $8 $8 $8 $36 

137
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Qualified Savings Plans

Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% (75% for employees covered under the traditional formula in the Retirement Plan) of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options.

Aggregate employer contributions to the qualified savings plans totaled $45 million, $46 million, and $33 million for the years ended December 31, 2025, 2024 and 2023, respectively.

17.STOCK-BASED COMPENSATION

Vistra 2016 Omnibus Incentive Plan

On the Effective Date, the Board adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons. Following approval of the Board and approval by the stockholders at the 2019 and 2024 annual meetings of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000 and 43,000,000, respectively. The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards, and (c) establish the terms and conditions of awards, including the price (if any) to be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock options, RSUs, restricted stock, performance awards, and other forms of awards granted or denominated in shares of Vistra common stock, as well as certain cash-based awards.

If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised award shall again be available for awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation. No awards under the 2016 Incentive Plan have been settled in cash since the Effective Date.

As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra stockholders.

Stock-Based Compensation Expense

Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows:
Year Ended December 31,
202520242023
(in millions)
Total stock-based compensation expense$113 $100 $77 
Income tax benefit(25)(23)(18)
Stock based-compensation expense, net of tax$88 $77 $59 

138
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Options

Stock options outstanding at December 31, 2025 are all held by current or former employees. The following table summarizes our stock option activity:
Year Ended December 31, 2025
Stock Options
(in thousands)		Weighted
Average Exercise Price		Weighted Average Remaining Contractual Term (Years)Aggregate Intrinsic Value (in millions)
Total outstanding at beginning of period3,600 $19.97 3.5$424.4 
Exercised(2,216)$18.89 
Forfeited or expired(6)$22.97 
Total outstanding at end of period1,378 $21.69 3.0$192.4 
Exercisable at December 31, 20251,378 $21.69 3.0$192.4 

As of December 31, 2025, there was no unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan and no new options were issued in the years ended December 31, 2025, 2024 and 2023.

Restricted Stock Units

The following table summarizes our restricted stock unit activity:
Year Ended December 31, 2025
Restricted Stock Units
(in thousands)		Weighted
Average Grant Date Fair Value
Total nonvested at beginning of period3,054 $34.30 
Granted518 $127.91 
Vested(1,624)$30.69 
Forfeited(124)$53.61 
Total nonvested at end of period1,824 $62.71 

As of December 31, 2025, $54 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 1.6 years.

Performance Stock Units

We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis. All PSUs have a three year performance period and a payout opportunity of 0-200% of target (100%), which is intended to be settled in shares of Vistra common stock. We recognized compensation expense associated with PSUs of $46 million, $54 million, and $36 million for the years ended December 31, 2025, 2024 and 2023, respectively. As of December 31, 2025, we have $54 million of unrecognized compensation cost associated with PSUs.

Employee Stock Purchase Plan (ESPP)

The Company offers participation in the ESPP which allows eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of Vistra common stock at the lesser of 85% of its market value on the offering date or 85% of the fair market value on the exercise date. An offering date occurs each January 1 and July 1 and an exercise date occurs each June 30 and December 31 beginning in 2026. The ESPP allows for the issuance of 1,000,000 shares of our common stock, all of which were available for purchase pursuant to the ESPP as of December 31, 2025.

139
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18.COMMITMENTS AND CONTINGENCIES

Contractual Commitments

As of December 31, 2025, we had minimum contractual commitments under long-term service and maintenance contracts, energy-related contracts and other agreements as follows:
Long-Term Service and Maintenance Contracts (a)Coal transportation agreementsPipeline transportation and storage reservation feesWater
Contracts
(in millions)
2026$182 $63 $227 $2 
2027257 27 245 10 
2028294 — 279 10 
2029243 — 284 10 
2030276 — 286 10 
Thereafter1,823 — 497 35 
Total$3,075 $90 $1,818 $77 
____________
(a)Long-term service and maintenance contracts reflect expected expenditures as these contracts do not include minimum spending requirements, but can only be terminated based on events outside the control of the Company.

In addition to the commitments detailed above, we have nuclear fuel contracts with early termination penalties. As of December 31, 2025, termination costs of $94 million would be incurred if we terminated those contracts.

Expenditures under our coal purchase and coal transportation agreements totaled $733 million, $744 million, and $936 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Letters of Credit, Surety Bonds, and Collateral Support Obligation

Letters of Credit — As of December 31, 2025, we had outstanding letters of credit totaling $3.004 billion as follows:

•$2.489 billion to support commodity risk management and collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and $679 million of collateral postings with ISOs/RTOs;
•$279 million to support battery and solar development projects;
•$110 million to support ASAOC requirements with the EPA (see Note 8 for additional information);
•$86 million to support our REP financial requirements with the PUCT;
•$25 million to support executory contracts and insurance agreements; and
•$15 million for other credit support requirements.

Surety Bonds — Surety bonds provide financial performance assurance to third parties on behalf of certain Company subsidiaries for obligations under various contracts and legal obligations in the normal course of business. In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety. Our liability with respect to any particular surety bond is released once the obligations secured by the surety bond are performed. As of December 31, 2025, we had outstanding surety bonds totaling $987 million, including $81 million with ISOs/RTOs.

Collateral Support Obligation — The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation of our assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.

140
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Litigation and Regulatory Proceedings

Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material.

Litigation

Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius Energy Trust in July 2019. The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the five-year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint.

Ohio House Bill 6 ("HB6") — In July 2019, Ohio adopted a law referred to as HB6, which, among other things, provided subsidies for two nuclear power plants which we acquired in March 2024 upon the closing of our merger with Energy Harbor. We had opposed enactment of that subsidy legislation at the time, and the nuclear subsidies were repealed in 2021 prior to any subsidies being distributed. The U.S. Attorney's Office conducted an investigation into the activities related to the passage of HB6, and Energy Harbor received a grand jury subpoena in July 2020 requiring production of certain information related to that investigation. Energy Harbor completed its responses to that subpoena by December 2021. In August 2020, the Ohio Attorney General filed a civil Racketeer Influenced and Corrupt Organizations Act (RICO) complaint against FirstEnergy Corp. and various Energy Harbor companies related to passage of HB6 (State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al., Franklin County, Ohio Common Pleas Court Case No. 20CV006281 and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. Energy Harbor Corp., et al., Franklin County, Ohio Common Pleas Court Case No. 20CV007386). Motions to dismiss those cases remain pending and the case is currently stayed.

Dorrell Antitrust Litigation — In July 2025, an antitrust lawsuit was filed in the U.S. District Court for the District of Maryland against Human Resources Consultants, LLC, Accelerant Technologies, Constellation Energy Corporation and 25 other companies, including Vistra Corp. and Luminant Generation Company, LLC. Plaintiffs allege that since at least May 2003, the defendants exchanged confidential compensation information and conspired to fix and suppress compensation of all persons employed in nuclear power generation in violation of federal antitrust law. In October 2025, motions to dismiss these claims were filed and the Plaintiffs amended their lawsuit. In December 2025, motions to dismiss these amended claims were filed. We believe we have strong defenses to this lawsuit and intend to defend against this case vigorously.

141
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Winter Storm Uri Legal Proceedings

Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, and the Texas Attorney General initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges for generators arising from the event, including performance and fuel and supply issues. We responded to all those investigatory requests. In addition, a large number of personal injury, wrongful death, and insurance lawsuits related to Winter Storm Uri have been filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. These cases were transferred to a single multi-district litigation (MDL) pretrial judge for all pretrial proceedings. In January 2023, the MDL court ruled on the various motions to dismiss and denied the motions to dismiss of the generator defendants and the transmission distribution utilities defendants, but granted the motions of some of the other defendant groups, including the retail electric providers and ERCOT. In December 2023, the First Court of Appeals in a unanimous decision granted our mandamus petition and instructed the MDL court to grant the motions to dismiss in full filed by the generator defendants. The plaintiffs have petitioned the Texas Supreme Court to review that decision and filed their opening brief in September 2025. We believe we have strong defenses to these lawsuits and intend to defend against these cases vigorously if they continue.

Moss Landing 300 Battery Fire

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site. We are working closely with all local, state, and federal regulatory authorities on the response, and we are investigating the cause of the fire. We are also responding to various regulatory bodies, including the CPUC, the EPA, and others investigating the incident. Several lawsuits have been filed in California federal and state courts against Vistra, LG Energy Solution (LG), and others, as a result of this incident.

The EPA is providing control and oversight of clean up and remediation efforts on the site. In July 2025, we entered into an ASAOC with the EPA that requires us to perform certain activities, which primarily include battery removal and disposal, building demolition, and air and water monitoring at the Moss Landing 300 site. By entering into this ASAOC, we will conduct these activities under the EPA's oversight. See Note 8 for additional information including costs incurred through December 31, 2025 and estimated future costs to be incurred related to these activities.

Unleashing American Energy Executive Order

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.

142
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.

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

In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (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

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.

143
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.

Effluent Limitation Guidelines (ELGs)

In October 2020, the EPA published a final rule that extends the compliance date for both flue gas desulfurization (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.

Coal Combustion Residuals (CCR) Rule Revisions and Extension Applications

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.

144
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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.

145
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.

Other Matters

We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity, or financial condition.

Nuclear Insurance

Nuclear insurance includes nuclear liability coverage, property damage, nuclear accident decontamination, and accidental premature decommissioning coverage, and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity, or financial condition.

With regard to nuclear liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $16.2 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $16.2 billion limit for a single incident. As required, we insure against a possible nuclear incident at our nuclear facilities resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP).

Under the SFP, in the event of any single nuclear liability loss in excess of $500 million at any nuclear generation facility in the U.S., each operating licensed reactor in the U.S. is subject to an assessment of up to $165.9 million. This approximately $165.9 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur by November 2028. Assessments are currently limited to $24.7 million per operating licensed reactor per year per incident. As of December 31, 2025, our maximum potential assessment under the industry retrospective plan would be approximately $995.4 million per incident but no more than $148.2 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $500 million per accident at any nuclear facility.

The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $1.06 billion of nuclear accident decontamination and reactor damage stabilization insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance for our facilities in the amount of $2.25 billion and non-nuclear accident related property damage in the amount of $1.0 billion. Coverage is subject to a $10 million deductible per accident including natural hazards except for the Davis-Besse facility which is subject to a $20 million deductible. Losses excluded or above such limits are self-insured.

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VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We also maintain Accidental Outage insurance to help cover the additional costs of obtaining replacement electricity from another source if the units are out of service for more than twelve weeks as a result of covered direct physical damage. Coverage at the Comanche Peak, Beaver Valley, and Perry facilities provide for weekly payments per unit up to $4.5 million for the first 52 weeks and up to $2.7 million for a remaining 21 weeks for non-nuclear accident property damage and up to $3.6 million for a remaining 71 weeks for nuclear accident property damage outages. The total maximum coverage is $291 million for non-nuclear accident property damage and $490 million for nuclear accident property damage outages. Coverage at the Davis-Besse facility provides for weekly payments per unit up to $2.5 million for the first 52 weeks and up to $1.5 million for a remaining 52 weeks for non-nuclear accident property damage and up to $2 million for a remaining 110 weeks for nuclear accident property damage outages. The total maximum coverage is $208 million for non-nuclear accident property damage and $350 million for nuclear accident property damage outages. There are two units at Comanche Peak and Beaver Valley, and coverage amounts applicable to each unit will reduce to 80% if both units are out of service at the same time as a result of the same accident.

19.EQUITY

Common Stock

Issuances and Repurchases

Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2025, 2024 and 2023 are reflected in the table below.
Shares
Issued		Treasury
Shares		Shares Outstanding
Balance at December 31, 2022537,179,072 (147,502,289)389,676,783 
Shares issued (a)6,474,491 — 6,474,491 
Shares retired(18,391)— (18,391)
Shares repurchased (b)— (44,994,499)(44,994,499)
Balance at December 31, 2023543,635,172 (192,496,788)351,138,384 
Shares issued (a)5,117,434 — 5,117,434 
Shares repurchased (b)— (16,560,328)(16,560,328)
Balance at December 31, 2024548,752,606 (209,057,116)339,695,490 
Shares issued (a)4,917,325 — 4,917,325 
Shares retired(10,771)— (10,771)
Shares repurchased (b)— (6,550,237)(6,550,237)
Balance at December 31, 2025553,659,160 (215,607,353)338,051,807 
____________
(a)Shares issued include share awards granted to nonemployee directors.
(b)Shares repurchased include 7,828, 58,817, and 318,632 of unsettled shares as of December 31, 2025, 2024 and 2023, respectively.

Common Stock Dividends

Dividends are subject to declaration by the Board and may be subject to numerous factors at the time of declaration. These factors include, but are not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law, and any contractual limitations, such as the cumulative dividend requirements described in the certificates of designation of our outstanding preferred stock. Dividends per common share totaled $0.9015, $0.8735, and $0.8205 in the years ended December 31, 2025, 2024 and 2023, respectively.

In February 2026, the Board declared a quarterly dividend of $0.2280 per share of common stock that will be paid in March 2026.

147
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Share Repurchase Program

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.
Amount Authorized for Share Repurchases
(in billions)
Board Authorization Dates:
October 2021$2.00 
August 20221.25 
March 20231.00 
February 20241.50 
October 20241.00 
October 2025
1.00 
Cumulative authorization at December 31, 2025
$7.75 

The following table provides information about our repurchases of common stock for the period between January 1, 2023 and February 18, 2026.
$7.750 Billion Board Authorization
Total Number of Shares RepurchasedAverage Price Paid
Per Share		Amount Paid for Shares RepurchasedAmount Available for Additional Repurchases at the End of the Period
(in millions, except share amounts and price paid per share)
Year Ended December 31, 202344,994,499$27.89 $1,255 
Year Ended December 31, 202416,560,32874.96 1,241 
Year Ended December 31, 20256,550,237154.00 1,009 
January 1, 2023 through December 31, 2025 (a)68,105,064$51.46 $3,505 $2,000 
January 1, 2026 through February 18, 20261,185,372159.80 189 
January 1, 2023 through February 18, 202669,290,436$53.32 $3,694 $1,811 
____________
(a)Shares repurchased include 7,828 of unsettled shares for $1 million as of December 31, 2025.

148
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Preferred Stock

The following is a summary of our cumulative redeemable preferred stock outstanding. In the event of liquidation or dissolution of the Company, the payment of dividends and the distribution of assets to preferred stockholders takes precedence over the Company's common stockholders.
Preferred Stock SeriesIssuance
Date
Shares Issued
Shares Outstanding
Contractual
Rates
Earliest Redemption Date (a)
Date at Which Dividend Rate Becomes FloatingFloating Annual Rates
Series AOctober 15,
2021		1,000,000 1,000,000 8.000 %October 15,
2026		October 15,
2026
5-Year U.S. Treasury rate (subject to floor of 1.07%) plus 6.93%
Series BDecember 10,
2021		1,000,000 1,000,000 7.000 %December 15,
2026		December 15,
2026
5-Year U.S. Treasury rate (subject to floor of 1.26%) plus 5.74%
Series CDecember 29,
2023		476,081 476,066 8.875 %January 15,
2029		January 15,
2029
5-Year U.S. Treasury rate (subject to floor of 3.83%) plus 5.045%
____________
(a)Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.

Each series of preferred stock has a liquidation price of $1,000, plus accrued and unpaid dividends through their redemption date. Preferred stock is not convertible into or exchangeable for any other securities of the Company and has limited voting rights.

Preferred Stock Dividends

Preferred stock dividends are payable semiannually in arrears when declared by the Board. The following table summarizes preferred stock dividends paid per share in the years ended December 31, 2025, 2024 and 2023.
Year Ended December 31,
Preferred Stock Series202520242023
Series A Preferred Stock$80.00 $80.00 $80.00 
Series B Preferred Stock$70.00 $70.00 $70.00 
Series C Preferred Stock$88.75 $48.32 

In October 2025, the Board declared a semi-annual dividend of $44.375 per share of Series C Preferred Stock that was paid in January 2026. In February 2026, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred Stock that will be paid in April 2026.

149
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
20.EARNINGS PER SHARE

Basic earnings per share available to common stockholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.
Year Ended December 31,
202520242023
(in millions, except share data)
Net income attributable to Vistra$944 $2,659 $1,493 
Less cumulative dividends attributable to Series A Preferred Stock(80)(80)(80)
Less cumulative dividends attributable to Series B Preferred Stock(70)(70)(70)
Less cumulative dividends attributable to Series C Preferred Stock(42)(42)— 
Net income attributable to common stock — basic and diluted752 2,467 1,343 
Weighted average shares of common stock outstanding:
Basic339,124,917 344,788,634 369,771,359 
Dilutive securities: Stock-based incentive compensation plan6,531,150 7,778,426 5,421,752 
Diluted345,656,067 352,567,060 375,193,110 
Net income (loss) per weighted average share of common stock outstanding:
Basic$2.22 $7.16 $3.63 
Diluted$2.18 $7.00 $3.58 

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive were immaterial in the years ended December 31, 2025 and 2024 and totaled 392,218 shares in the year ended December 31, 2023.

21.SEGMENT INFORMATION

The operations of Vistra are aligned into five reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. Our Chief Executive Officer is our chief operating decision maker (CODM). Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources. In the fourth quarter of 2024, we updated our reportable segments to reflect changes in how the Company's CODM makes operating decisions, assesses performance, and allocates resources by removing the Sunset segment. The results of the plants previously included in the Sunset segment are now reflected in the Texas and East segments based on their respective geographies.

The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial, and industrial customers. Substantially all of these activities are conducted by TXU Energy, Ambit Energy, Dynegy Energy Services, Homefield Energy, Energy Harbor, and U.S. Gas & Electric across 16 states and the District of Columbia.

The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel procurement, and logistics management. The Texas segment represents results from all of Vistra's electricity generation operations in the ERCOT market except for assets included in the Asset Closure segment. The East segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets included in the Asset Closure segment, and includes operations in the PJM, MISO, ISO-NE, and NYISO markets.

The West segment represents results from the CAISO market, including our battery ESS project at our Moss Landing power plant site. The Moss Landing 300 MW and Moss Landing 100 MW battery facilities were transferred to the Asset Closure segment in the first quarter of 2025 and fourth quarter of 2025, respectively, as a result of the Moss Landing Incident (see Note 8 for additional information). Management concluded that the 2023 and 2024 revenues, expenses, and capital expenditures associated with the Moss Landing 100 MW battery were immaterial, therefore, prior‑period segment results have not been recast.

150
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Asset Closure segment is engaged in the decommissioning and reclamation of retired generation facilities, including mines, and battery removal and remediation activities. When facilities are transferred to the Asset Closure segment, prior period results are retrospectively adjusted for comparative purposes, provided the effects are material (see Note 7 for additional information). By separately reporting the Asset Closure segment, management gains improved insights into the performance and earnings potential of Vistra's ongoing operations while actively monitoring the cost associated with Asset Closure activities.

Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes, other expenses, and nuclear fuel cash capital expenditures not allocated to our operating segments.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. Our CODM uses more than one measure to assess segment performance, but primarily focuses on Adjusted EBITDA. While we believe this is a useful metric in evaluating operating performance, it is not a metric defined by U.S. GAAP and may not be comparable to non-GAAP metrics presented by other companies. Adjusted EBITDA is most comparable to consolidated Net income (loss) prepared based on U.S. GAAP. The CODM uses net income in competitive analysis by benchmarking to the Company's competitors and evaluating drivers of segment profits available to the Company's equity holders. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments. Substantially all income tax (expense) benefit is recognized in Corporate and Other.

Year Ended December 31, 2025
RetailTexasEastWest
Asset Closure
Total Reportable Segments
(in millions)
Operating revenues (a)
$14,340 $5,353 $6,174 $325 $74 $26,266 
Reconciliation of consolidated operating revenues:
Corporate and Other
(8,528)
Total consolidated operating revenues
$17,738 
Fuel, purchased power costs, and delivery fees (b)
(11,686)(1,990)(3,807)(149)— 
Operating costs(168)(1,050)(1,381)(59)(154)
Selling, general, and administrative expenses(1,035)(180)(235)(14)(66)
Other segment items:
Depreciation and amortization(94)(638)(1,120)(61)2 
Interest expenses and related charges(67)53 50 7 (4)
Income tax expense
— — (1)— — 
Other (c)
— 56 229 5 (131)
Total reportable segment net income (loss)
$1,290 $1,604 $(91)$54 $(279)$2,578 
Reconciliation to consolidated income before income taxes:
Corporate and Other - net loss
(1,634)
Corporate and Other - income tax expense
179 
Total consolidated income before income taxes
$1,123 
Capital expenditures, including nuclear fuel and excluding growth expenditures
$12 $954 $647 $186 $— $1,799 
Reconciliation to consolidated capital expenditures, including nuclear fuel and excluding growth expenditures
Corporate and Other - nuclear fuel net purchases
$305 
Total capital expenditures, including nuclear fuel and excluding growth expenditures
$2,104 
151
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
____________
(a)See Note 3 for disaggregated revenue by segment. Includes intersegment sales eliminated in Corporate and Other.
(b)Includes nuclear fuel amortization of $133 million and $354 million, respectively, in the Texas and East segments.
(c)Other includes impairment of long-lived assets and other income, net.

Year Ended December 31, 2024
RetailTexasEastWest
Asset Closure
Total Reportable Segments
(in millions)
Operating revenues (a)
$12,797 $5,394 $5,661 $839 $39 $24,730 
Reconciliation of consolidated operating revenues:
Corporate and Other
(7,506)
Total consolidated operating revenues$17,224 
Fuel, purchased power costs, and delivery fees (b)
(10,276)(1,596)(2,698)(218)(6)
Operating costs(159)(996)(1,103)(52)(101)
Selling, general, and administrative expenses(977)(169)(148)(20)(48)
Other segment items:
Depreciation and amortization(114)(581)(996)(58)(28)
Interest expenses and related charges(54)46 9 1 (4)
Other (c)
(1)35 177 (6)17 
Total reportable segment net income (loss)$1,216 $2,133 $902 $486 $(131)$4,606 
Reconciliation to consolidated income before income taxes:
Corporate and Other - net loss
(1,794)
Corporate and Other - income tax expense
655 
Total consolidated income before income taxes$3,467 
Capital expenditures, including nuclear fuel and excluding growth expenditures
$4 $751 $557 $68 $2 $1,382 
Reconciliation to consolidated capital expenditures, including nuclear fuel and excluding growth expenditures
Corporate and Other - nuclear fuel net purchases
$345 
Total capital expenditures, including nuclear fuel and excluding growth expenditures$1,727 
____________
(a)See Note 3 for disaggregated revenue by segment. Includes intersegment sales eliminated in Corporate and Other.
(b)Includes nuclear fuel amortization of $105 million and $282 million, respectively, in the Texas and East segments.
(c)Other includes other income, net and the impacts of the Tax Receivable Agreement.

152
VISTRA CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31, 2023
RetailTexasEastWest
Asset Closure
Total Reportable Segments
(in millions)
Operating revenues (a)
$10,572 $3,979 $5,890 $866 $48 $21,355 
Reconciliation of consolidated operating revenues:
Corporate and Other
$(6,576)
Total consolidated operating revenues$14,779 
Fuel, purchased power costs, and delivery fees(9,046)(2,028)(2,730)(326)(5)
Operating costs(123)(917)(528)(42)(90)
Selling, general, and administrative expenses(858)(140)(127)(22)(36)
Other segment items:
Depreciation and amortization(102)(550)(703)(52)(27)
Interest expenses and related charges(20)21 (2)8 (5)
Income tax expense
— — (1)— — 
Other (b)
1 33 (50)2 129 
Total reportable segment net income (loss)$424 $398 $1,749 $434 $14 $3,019 
Reconciliation to consolidated income before income taxes:
Corporate and Other - net loss
(1,527)
Corporate and Other - income tax expense
508 
Total consolidated income before income taxes$2,000 
Capital expenditures, including nuclear fuel and excluding growth expenditures
$1 $536 $362 $364 $2 $1,265 
Reconciliation to consolidated capital expenditures, including nuclear fuel and excluding growth expenditures
Corporate and Other - nuclear fuel net purchases
$206 
Total capital expenditures, including nuclear fuel and excluding growth expenditures$1,471 
____________
(a)See Note 3 for disaggregated revenue by segment. Includes intersegment sales eliminated in Corporate and Other.
(b)Other includes impairment of long-lived assets, other income, net and the impacts of the Tax Receivable Agreement.

153
VISTRA CORP.
Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A.CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) in effect at December 31, 2025. Based on the evaluation performed, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective as of that date.

There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

VISTRA CORP.
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Vistra Corp. is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Vistra Corp.'s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.

The management of Vistra Corp. performed an evaluation of the effectiveness of the company's internal control over financial reporting as of December 31, 2025 based on the Committee of Sponsoring Organizations of the Treadway Commission's (COSO's) Internal Control - Integrated Framework (2013). Based on the review performed, management believes that as of December 31, 2025 Vistra Corp.'s internal control over financial reporting was effective.

The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Vistra Corp. has issued an attestation report on Vistra Corp.'s internal control over financial reporting.

/s/ JAMES A. BURKE/s/ KRISTOPHER E. MOLDOVAN
James A. BurkeKristopher E. Moldovan
President and Chief Executive OfficerChief Financial Officer
(Principal Executive Officer)(Principal Financial Officer)

February 26, 2026

154
VISTRA CORP.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Vistra Corp.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Vistra Corp. and subsidiaries (the "Company") as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2025, of the Company and our report dated February 26, 2026, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Dallas, Texas
February 26, 2026

Item 9B.OTHER INFORMATION

During the three months ended December 31, 2025, none of our officers or directors adopted or terminated any contract, instruction, or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement," except as set forth below:

155
VISTRA CORP.
On December 2, 2025, Stephanie Zapata Moore, Executive Vice President, General Counsel and Chief Compliance Officer of the Company, entered into a trading plan intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) of the Exchange Act (10b5-1 Plan). Moore's 10b5-1 Plan provides for the potential sale of up to 57,500 shares of our common stock. Any sales are subject to certain price limitations set forth in the 10b5-1 Plan such that the actual number of shares sold could vary if certain minimum stock prices are not met. Moore's 10b5-1 Plan will become effective on March 9, 2026 and will terminate on October 30, 2026, subject to earlier termination as provided in the 10b5-1 Plan. Moore's 10b5-1 Plan was entered into during an open insider trading window in accordance with our Transactions in Securities Policy.

On December 1, 2025, Scott Hudson, Executive Vice President and President of Vistra Retail of the Company, entered into a 10b5-1 Plan. Hudson's 10b5-1 Plan provides for the potential sale of up to 27,000 shares of our common stock. Any sales are subject to certain price limitations set forth in the 10b5-1 Plan such that the actual number of shares sold could vary if certain minimum stock prices are not met. Hudson's 10b5-1 Plan will become effective on March 9, 2026 and will terminate on August 31, 2026, subject to earlier termination as provided in the 10b5-1 Plan. Hudson's 10b5-1 Plan was entered into during an open insider trading window in accordance with our Transactions in Securities Policy.

On December 1, 2025, Stacey Doré, Chief Strategy and Sustainability Officer and Executive Vice President of Public Affairs of the Company, entered into a 10b5-1 Plan. Doré's 10b5-1 Plan provides for the potential sale of up to 36,000 shares of our common stock. Any sales are subject to certain price limitations set forth in the 10b5-1 Plan such that the actual number of shares sold could vary if certain minimum stock prices are not met. Doré's 10b5-1 Plan will become effective on March 9, 2026 and will terminate on December 31, 2026, subject to earlier termination as provided in the 10b5-1 Plan. Doré's 10b5-1 Plan was entered into during an open insider trading window in accordance with our Transactions in Securities Policy.

Item 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

156
VISTRA CORP.
PART III

Item 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Code of Ethics

Vistra has adopted a code of ethics entitled "Vistra Code of Conduct" that applies to directors, officers, and employees, including the chief executive officer and senior financial officers of Vistra. It may be accessed through the "Corporate Governance" section of the Company's website at www.vistracorp.com. Vistra also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website and will disclose such events within four business days following the date of the amendment or waiver, and such information will remain available on this website for at least a 12-month period. A copy of the "Vistra Code of Conduct" is available in print to any stockholder who requests it.

Other information required by this Item is incorporated by reference to the section entitled "Corporate Governance" in Vistra's Definitive Proxy Statement for its 2026 Annual Meeting of Stockholders.

Item 11.EXECUTIVE COMPENSATION

Information required by this Item is incorporated by reference to the section entitled "Compensation Discussion and Analysis" in Vistra's Definitive Proxy Statement for its 2026 Annual Meeting of Stockholders.

Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this Item is incorporated by reference to the section entitled "Beneficial Ownership of Common Stock of the Company" in Vistra's Definitive Proxy Statement for its 2026 Annual Meeting of Stockholders.

Item 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by this Item is incorporated by reference to the sections entitled "Business Relationships and Related Person Transactions Policy" and "Director Independence" in Vistra's Definitive Proxy Statement for its 2026 Annual Meeting of Stockholders.

Item 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by this Item is incorporated by reference to the section entitled "Principal Accountant Fees" in Vistra's Definitive Proxy Statement for its 2026 Annual Meeting of Stockholders.

Deloitte & Touche LLP's PCAOB ID Number is 34.

157
VISTRA CORP.
PART IV

Item 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)    Our financial statements and financial statement schedules are incorporated under Part II, Item 8 of this annual report on Form 10-K.

(b)    SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS
(Millions of Dollars)
Year Ended December 31,
202520242023
Depreciation and amortization$— $— $(15)
Selling, general, and administrative expenses(114)(102)(80)
Operating loss(114)(102)(95)
Other income2 28 31 
Impacts of Tax Receivable Agreement2 (5)(164)
Loss before income tax benefit(110)(79)(228)
Income tax benefit20 17 58 
Equity in earnings of subsidiaries, net of tax1,034 2,721 1,663 
Net income$944 $2,659 $1,493 

See Notes to the Condensed Financial Statements.

158
VISTRA CORP.
VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(Millions of Dollars)
December 31,
20252024
ASSETS
Cash and cash equivalents$67 $22 
Trade accounts receivable — affiliates15 13 
Income taxes receivable63 8 
Total current assets145 43 
Investment in affiliated companies4,001 4,670 
Property, plant, and equipment — net2 2 
Accumulated deferred income taxes1,067 960 
Other noncurrent assets— 3 
Total assets$5,215 $5,678 
LIABILITIES AND EQUITY
Trade accounts payable$1 $8 
Accounts payable —affiliates41 27 
Accrued taxes3 9 
Other current liabilities20 27 
Total current liabilities65 71 
Tax Receivable Agreement obligations7 14 
Other noncurrent liabilities and deferred debits33 10 
Total liabilities105 95 
Total stockholders' equity5,110 5,583 
Total liabilities and equity$5,215 $5,678 

See Notes to the Condensed Financial Statements.

159
VISTRA CORP.
VISTRA CORP. (PARENT)
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
202520242023
Cash flows — operating activities:
Cash used in operating activities$(44)$(37)$(31)
Cash flows — investing activities:
Dividend received from subsidiaries1,625 1,705 1,625 
Proceeds from sales of subsidiary transferable ITCs— 150 — 
Cash provided by investing activities1,625 1,855 1,625 
Cash flows — financing activities:
Stock repurchases(1,028)(1,266)(1,245)
Dividends paid to common stockholders(306)(305)(313)
Dividends paid to preferred stockholders(192)(173)(150)
TRA Repurchase and tender offer - return of capital— (122)— 
Other, net(10)39 91 
Cash used in financing activities(1,536)(1,827)(1,617)
Net change in cash, cash equivalents, and restricted cash45 (9)(23)
Cash, cash equivalents, and restricted cash — beginning balance22 31 54 
Cash, cash equivalents, and restricted cash — ending balance$67 $22 $31 

See Notes to the Condensed Financial Statements.


NOTES TO CONDENSED FINANCIAL STATEMENTS

1.BASIS OF PRESENTATION

The accompanying unconsolidated condensed balance sheets, statements of net loss and cash flows present results of operations and cash flows of Vistra Corp. (Parent). Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the financial statements and related notes of Vistra Corp. and Subsidiaries included in the annual report on Form 10-K for the year ended December 31, 2025. Vistra Corp.'s subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated.

Parent files a consolidated U.S. federal income tax return. Consolidated tax expenses or benefits and deferred tax assets or liabilities have been allocated to the respective subsidiaries in accordance with the accounting rules that apply to separate financial statements of subsidiaries.

2.RESTRICTIONS ON SUBSIDIARIES

The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2025, Vistra Operations can distribute approximately $11.2 billion to Parent without the consent of any party. The amount available for distribution has been reduced by distributions made by Vistra Operations to Parent of approximately $1.625 billion, $1.705 billion, and $1.625 billion during the years ended December 31, 2025, 2024 and 2023, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2025, all of the restricted net assets of Vistra Operations may be distributed to Parent.

160
VISTRA CORP.
3.GUARANTEES

Parent has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31, 2025, there are no material outstanding claims related to guarantee obligations of Parent, and Parent does not anticipate it will be required to make any material payments under these guarantees in the near term.

4.DIVIDEND RESTRICTIONS

Under applicable law, Parent is prohibited from paying any dividend to the extent that immediately following payment of such dividend there would be no statutory surplus or Parent would be insolvent.

Parent received $1.625 billion, $1.705 billion, and $1.625 billion in dividends from its consolidated subsidiaries in the years ended December 31, 2025, 2024 and 2023, respectively.

(c)    EXHIBITS:

Vistra Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2025
ExhibitsPreviously Filed With File Number*As
Exhibit
(2)Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2.1
001-38086
Form 8-K
(filed March 7, 2023)
2.1—
Transaction Agreement, dated March 6, 2023, by and among Vistra Operations Company LLC, Black Pen Inc. and Energy Harbor Corp.
2.2
001-38086
Form 8-K
(filed May 21, 2025)
2.1—
Purchase and Sale Agreement, dated May 15, 2025, by and among Vistra Operations Company LLC, NEP Holdco 1, L.L.C., NatGas Fund Holdings, L.L.C., SEIF III NatGas Holdings, L.L.C. and Edgewater Parent, L.L.C.
2.3
001-38086
Form 8-K
(filed January 5, 2026)
2.1—
Purchase and Sale Agreement, dated as of December 31, 2025, by and among Q-Generation Holdings, LLC, Vistra Operations Company LLC and Vistra Corp.
2.4
001-38086
Form 8-K
(filed January 5, 2026)
2.2—
Agreement and Plan of Merger, dated as of December 31, 2025, by and among Hamilton Holdings II, LLC, Vistra Operations Company LLC, TSVME LLC and Q-Generation Holdings, LLC.
(3(i))Articles of Incorporation
3.1
001-38086
Form 8-K
(filed on May 5, 2025)
3.1
—
Amended and Restated Certificate of Incorporation of Vistra Corp.
3.2
001-38086
Form 8-K
(filed on October 15, 2021)		3.1—
Series A Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on October 14, 2021
3.3
001-38086
Form 8-K (filed
on December 13, 2021)		3.1—
Series B Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on December 9, 2021
3.4
001-38086
Form 8-K (filed
on January 4, 2024)		3.1—
Series C Preferred Stock Certificate of Designation filed with the Secretary of State of Delaware on December 29, 2023
(3(ii))By-laws
3.5
001-38086
Form 8-K
(filed on May 5, 2025)
3.2
—
(4)Instruments Defining the Rights of Security Holders, Including Indentures
4.1
001-38086
Form 8-K
(filed on February 6, 2019)		4.1—
Indenture for 5.625% Senior Note due 2027, dated as of February 6, 2019, among Vistra Operations Company LLC, as issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
161
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.2
001-38086
Form 8-K
(filed on February 6, 2019)		4.2—
Form of Rule 144A Global Security for 5.625% Senior Note due 2027 (included in Exhibit 4.1)

4.3
001-38086
Form 8-K
(filed on February 6, 2019)		4.3—
Form of Regulation S Global Security for 5.625% Senior Note due 2027 (included in Exhibit 4.1)

4.4
001-38086
Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019)		4.6—
First Supplemental Indenture for the 5.625% Senior Notes due 2027, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.5
001-38086
Form 10-K (Year ended December 31, 2019) (filed
on February 28, 2020)		4.41—
Second Supplemental Indenture for the 5.625% Senior Notes due 2027, dated October 25, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.6
001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020)		4.7—
Third Supplemental Indenture for the 5.625% Senior Notes due 2027, dated January 31, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.7
001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020)		4.8—
Fourth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated March 26, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.8
001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		4.17—
Fifth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated October 7, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.9
001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		4.18—
Sixth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated January 8, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.10
001-38086
Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021)		4.4—
Seventh Supplemental Indenture for the 5.625% Senior Notes due 2027, dated July 29, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.11
001-38086
Form 10-K (Year ended December 31, 2021) (filed
on February 25, 2022)		4.22—
Eighth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated December 28, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.12
001-38086
Form 10-K (Year ended December 31, 2022) (filed
on March 1, 2023)		4.24—
Ninth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated December 15, 2022, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.13
001-38086
Form 10-Q (Quarter ended September 30, 2023) (filed on November 7, 2023)		4.2—
Tenth Supplemental Indenture for the 5.625% Senior Notes due 2027, dated July 31, 2023, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.14
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
4.29
—
Eleventh Supplemental Indenture for the 5.625% Senior Notes due 2027, dated October 20, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.15
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.7—
Twelfth Supplemental Indenture for 5.625% Senior Notes due 2027, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
162
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.16
001-38086
Form 10-Q (Quarter ended March 31, 2025) (filed on May 8, 2025)
4.2
—
Thirteenth Supplemental Indenture for 5.625% Senior Notes due 2027, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.17
**
—
Fourteenth Supplemental Indenture for 5.625% Senior Notes, dated as of August 25, 2025, among BlueGen 1 LLC, Vistra Operations Company LLC, the other subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee
4.18
**
—
Fifteenth Supplemental Indenture for 5.625% Senior Notes, dated as of November 14, 2025, among the Subsidiary Guarantors, Vistra Operations Company LLC, and Wilmington Trust, National Association, as trustee
4.19
001-38086
Form 8-K
(filed on June 24, 2019)		4.1—
Indenture for 5.00% Senior Notes due 2027, dated as of June 21, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
4.20
001-38086
Form 8-K
(filed on June 24, 2019)		4.2—
Form of Rule 144A Global Security for 5.00% Senior Notes due 2027 (included in Exhibit 4.1)
4.21
001-38086
Form 8-K
(filed on June 24, 2019)		4.3—
Form of Regulation S Global Security for 5.00% Senior Notes due 2027 (included in Exhibit 4.1)
4.22
001-38086
Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019)		4.7—
First Supplemental Indenture for the 5.000% Senior Notes due 2027, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.23
001-38086
Form 10-K (Year ended December 31, 2019) (filed
on February 28, 2020)		4.46—
Second Supplemental Indenture for the 5.000% Senior Notes due 2027, dated October 25, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.24
001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020)		4.9—
Third Supplemental Indenture for the 5.000% Senior Notes due 2027, dated January 31, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.25
001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020)		4.10—
Fourth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated March 26, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.26
001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		4.26—
Fifth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated October 7, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.27
001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		4.27—
Sixth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated January 8, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.28
001-38086
Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021)		4.5—
Seventh Supplemental Indenture for the 5.000% Senior Notes due 2027, dated July 29, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.29
001-38086
Form 10-K (Year ended December 31, 2021) (filed
on February 25, 2022)		4.33—
Eighth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated December 28, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
163
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.30
001-38086
Form 10-K (Year ended December 31, 2022) (filed
on March 1, 2023)		4.36—
Ninth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated December 15, 2022, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.31
001-38086
Form 10-Q (Quarter ended September 30, 2023) (filed on November 7, 2023)		4.3—
Tenth Supplemental Indenture for the 5.000% Senior Notes due 2027, dated July 31, 2023, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee
4.32
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
4.44
—
Eleventh Supplemental Indenture for the 5.000% Senior Notes due 2027, dated October 20, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.33
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.8—
Twelfth Supplemental Indenture for 5.00% Senior Notes due 2027, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.34
001-38086
Form 10-Q (Quarter ended March 31, 2025) (filed on May 8, 2025)
4.3
—
Thirteenth Supplemental Indenture for 5.000% Senior Notes due 2027, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.35
**
—
Fourteenth Supplemental Indenture for 5.000% Senior Notes due 2027, dated as of August 25, 2025, among BlueGen 1 LLC, Vistra Operations Company LLC, the other subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee
4.36
**
—
Fifteenth Supplemental Indenture for 5.000% Senior Notes due 2027, dated as of November 14, 2025, among the Subsidiary Guarantors, Vistra Operations Company LLC, and Wilmington Trust, National Association, as trustee
4.37
001-38086
Form 8-K
(filed on June 17, 2019)		4.1—
Indenture, dated as of June 11, 2019, between Vistra Operations Company LLC, as Issuer, and Wilmington Trust, National Association, as Trustee
4.38
001-38086
Form 8-K
(filed on June 17, 2019)		4.2—
Supplemental Indenture for 3.55% Senior Secured Notes due 2024 and 4.30% Senior Secured Notes Due 2029, dated as of June 11, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
4.39
001-38086
Form 8-K
(filed on June 17, 2019)		4.4—
Form of Rule 144A Global Security for 4.30% Senior Notes due 2029 (included in Exhibit 4.2)
4.40
001-38086
Form 8-K
(filed on June 17, 2019)		4.6—
Form of Regulation S Global Security for 4.30% Senior Notes due 2029 (included in Exhibit 4.2)
4.41
001-38086
Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019)		4.8—
Second Supplemental Indenture for 4.30% Senior Secured Notes due 2029, dated as of August 30, 2019, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.42
001-38086
Form 8-K (filed
on November 21, 2019)		4.1—
Third Supplemental Indenture for 4.30% Senior Secured Notes due 2029, dated as of October 25, 2019, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, Subsidiary Guarantors and the Trustee
4.43
001-38086
Form 8-K (filed
on November 21, 2019)		4.2—
Fourth Supplemental Indenture for 3.70% Senior Secured Notes due 2027, dated as of November 15, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee
164
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.44
001-38086
Form 8-K (filed
on November 21, 2019)		4.3—
Form of Rule 144A Global Security for 3.70% Senior Note due 2027 (included in Exhibit 4.2)
4.45
001-38086
Form 8-K (filed
on November 21, 2019)		4.4—
Form of Regulation S Global Security for 3.70% Senior Note due 2027 (included in Exhibit 4.2)
4.46
001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020)		4.11—
Fifth Supplemental Indenture for 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of January 31, 2020, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.47
001-38086
Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020)		4.12—
Sixth Supplemental Indenture for 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of March 26, 2020, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.48
001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		4.41—
Seventh Supplemental Indenture for 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of October 7, 2020, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.49
001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		4.42—
Eighth Supplemental Indenture for 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of January 8, 2021, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.50
001-38086
Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021)		4.6—
Ninth Supplemental Indenture for 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of July 29, 2021, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.51
001-38086
Form 10-K (Year ended December 31, 2021) (filed
on February 25, 2022)		4.50—
Tenth Supplemental Indenture for 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of December 28, 2021, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.52
001-38086
Form 10-K (Year ended December 31, 2022) (filed
on March 1, 2023)		4.55—
Twelfth Supplemental Indenture for 3.70% Senior Secured Notes due 2027, 4.30% Senior Secured Notes due 2029, 4.875% Senior Secured Notes due 2024 and 5.125% Senior Secured Notes due 2025, dated as of December 15, 2022, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.53
001-38086
Form 10-Q (Quarter ended September 30, 2023) (filed on November 7, 2023)		4.4—
Thirteenth Supplemental Indenture for 3.70% Senior Secured Notes due 2027, 4.30% Senior Secured Notes due 2029, 4.875% Senior Secured Notes due 2024 and 5.125% Senior Secured Notes due 2025, dated as of July 31, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.54
001-38086
Form 8-K
(filed on October 2, 2023)		4.1—
Fourteenth Supplemental Indenture for the 6.950% Senior Secured Notes due 2033, dated as of September 26, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.55
001-38086
Form 8-K
(filed on October 2, 2023)
4.3
—
Form of Rule 144A Global Security for 6.950% Senior Secured Note due 2033 (included in Exhibit 4.1)
165
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.56
001-38086
Form 8-K
(filed on October 2, 2023)
4.4
—
Form of Regulation S Global Security for 6.950% Senior Secured Note due 2033 (included in Exhibit 4.1)
4.57
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
4.67
—
Fifteenth Supplemental Indenture for 4.30% Senior Secured Notes due 2029, 3.70% Senior Secured Notes due 2027 and 6.950% Senior Secured Notes due 2033, dated October 20, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.58
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.9—
Sixteenth Supplemental Indenture for 4.30% Senior Secured Notes due 2029, 3.70% Senior Secured Notes due 2027 and 6.950% Senior Secured Notes due 2033, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.59
001-38086
Form 8-K
(filed on April 18, 2024)		4.1—
Seventeenth Supplemental Indenture for 6.000% Senior Secured Notes due 2034, dated as of April 12, 2024, between Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, and Wilmington Trust, National Association, as Trustee
4.60
001-38086
Form 8-K
(filed on April 18, 2024)
4.3
—
Form of Rule 144A Global Security for 6.000% Senior Secured Note due 2034 (included in Exhibit 4.1)
4.61
001-38086
Form 8-K
(filed on April 18, 2024)
4.5
—
Form of Regulation S Global Security for 6.000% Senior Secured Note due 2034 (included in Exhibit 4.1)
4.62
001-38086
Form 8-K
(filed on December 9, 2024)		4.1—
Eighteenth Supplemental Indenture for 5.050% Senior Secured Notes due 2026 and 5.700% Senior Secured Notes due 2034, dated as of December 4, 2024, between Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, and Wilmington Trust, National Association, as Trustee
4.63
001-38086
Form 8-K
(filed on December 9, 2024)		4.2—
Form of Rule 144A Global Security for 5.050% Senior Secured Note due 2026 (included in Exhibit 4.1)
4.64
001-38086
Form 8-K
(filed on December 9, 2024)		4.3—
Form of Rule 144A Global Security for 5.700% Senior Secured Note due 2034 (included in Exhibit 4.1)
4.65
001-38086
Form 8-K
(filed on December 9, 2024)		4.4—
Form of Regulation S Global Security for 5.050% Senior Secured Note due 2026 (included in Exhibit 4.1)
4.66
001-38086
Form 8-K
(filed on December 9, 2024)		4.5—
Form of Regulation S Global Security for 5.700% Senior Secured Note due 2034 (included in Exhibit 4.1)
4.67
001-38086
Form 10-Q (Quarter ended March 31, 2025) (filed on May 8, 2025)
4.4
—
Nineteenth Supplemental Indenture for 4.300% Senior Secured Notes due 2029, 3.70% Senior Secured Notes due 2027, 6.950% Senior Secured Notes due 2033, 6.000% Senior Secured Notes due 2034, 5.050% Senior Secured Notes due 2026 and 5.700% Senior Secured Notes due 2034, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
166
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.68
**
—
Twentieth Supplemental Indenture for 4.300% Senior Secured Notes due 2029, 3.70% Senior Secured Notes due 2027, 6.950% Senior Secured Notes due 2033, 6.000% Senior Secured Notes due 2034, 5.050% Senior Secured Notes due 2026 and 5.700% Senior Secured Notes due 2034, dated as of August 25, 2025, among BlueGen 1 LLC, Vistra Operations Company LLC, the other subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee
4.69
001-38086
Form 8-K
(filed on October 15, 2025)
4.2
—
Twenty-First Supplemental Indenture for 4.300% Senior Secured Notes due 2028, 4.600% Senior Secured Notes due 2030 and 5.250% Senior Secured Notes due 2035, dated as of October 10, 2025, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, and Wilmington Trust, National Association, as Trustee
4.70
001-38086
Form 8-K
(filed on October 15, 2025)
4.3
—
Form of Rule 144A Global Security for 4.300% Senior Secured Note due 2028 (included in Exhibit 4.2)
4.71
001-38086
Form 8-K
(filed on October 15, 2025)
4.4
—
Form of Rule 144A Global Security for 4.600% Senior Secured Note due 2030 (included in Exhibit 4.2)
4.72
001-38086
Form 8-K
(filed on October 15, 2025)
4.5
—
Form of Rule 144A Global Security for 5.250% Senior Secured Note due 2035 (included in Exhibit 4.2)
4.73
001-38086
Form 8-K
(filed on October 15, 2025)
4.6
—
Form of Regulation S Global Security for 4.300% Senior Secured Note due 2028 (included in Exhibit 4.2)
4.74
001-38086
Form 8-K
(filed on October 15, 2025)
4.7
—
Form of Regulation S Global Security for 4.600% Senior Secured Note due 2030 (included in Exhibit 4.2)
4.75
**
—
Twenty-Second Supplemental Indenture for 4.300% Senior Secured Notes due 2029, 3.70% Senior Secured Notes due 2027, 6.950% Senior Secured Notes due 2033, 6.000% Senior Secured Notes due 2034, 5.050% Senior Secured Notes due 2026, 5.700% Senior Secured Notes due 2034, 4.300% Senior Secured Notes due 2028, 4.600% Senior Secured Notes due 2030 and 5.250% Senior Secured Notes due 2035 dated as of November 14, 2025, among the Subsidiary Guarantors, Vistra Operations Company LLC, and Wilmington Trust, National Association, as trustee
4.76
001-38086
Form 8-K
(filed on October 15, 2025)
4.8
—
Form of Regulation S Global Security for 5.250% Senior Secured Note due 2035 (included in Exhibit 4.2)
4.77
001-38086
Form 8-K
(filed on April 18, 2024)		4.2—
Indenture for 6.875% Senior Notes due 2032, dated as of April 12, 2024, between Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, and Wilmington Trust, National Association, as Trustee
4.78
001-38086
Form 8-K
(filed on April 18, 2024)		4.4—
Form of Rule 144A Global Security for 6.875% Senior Note due 2032 (included in Exhibit 4.2)
4.79
001-38086
Form 8-K
(filed on April 18, 2024)		4.6—
Form of Regulation S Global Security for 6.875% Senior Note due 2032 (included in Exhibit 4.2)
4.80
001-38086
Form 10-Q (Quarter ended March 31, 2025) (filed on May 8, 2025)
4.7
—
First Supplemental Indenture for 6.875% Senior Notes due 2032, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
167
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.81
**
—
Second Supplemental Indenture for 6.875% Senior Notes due 2032, dated as of August 25, 2025, among BlueGen 1 LLC, Vistra Operations Company LLC, the other subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee
4.82
**
—
Third Supplemental Indenture for 6.875% Senior Notes due 2032, dated as of November 14, 2025, among the Subsidiary Guarantors, Vistra Operations Company LLC, and Wilmington Trust, National Association, as trustee
4.83
001-38086
Form 8-K
(filed on October 2, 2023)		4.2—
Indenture for the 7.750% Senior Unsecured Notes due 2031, dated as of September 26, 2023, by and among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors and the Trustee
4.84
001-38086
Form 8-K
(filed on October 2, 2023)		4.5—
Form of Rule 144A Global Security for 7.750% Senior Unsecured Note due 2031 (included in Exhibit 4.2)
4.85
001-38086
Form 8-K
(filed on October 2, 2023)		4.6—
Form of Regulation S Global Security for 7.750% Senior Unsecured Note due 2031 (included in Exhibit 4.2)
4.86
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
4.85
—
First Supplemental Indenture for 7.750% Senior Secured Notes due 2031, dated October 20, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.87
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.3—
Second Supplemental Indenture for 7.750% Senior Secured Notes due 2031, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.88
001-38086
Form 10-Q (Quarter ended March 31, 2025) (filed on May 8, 2025)
4.5
—
Third Supplemental Indenture for 7.750% Senior Secured Notes due 2031, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.89
**
—
Fourth Supplemental Indenture for 7.750% Senior Secured Notes, dated as of August 25, 2025, among BlueGen 1 LLC, Vistra Operations Company LLC, the other subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee
4.90
**
—
Fifth Supplemental Indenture for 7.750% Senior Secured Notes, dated as of November 14, 2025, among the Subsidiary Guarantors, Vistra Operations Company LLC, and Wilmington Trust, National Association, as trustee
4.91
001-38086
Form 8-K
(filed on May 11, 2021)		4.1—
Indenture for 4.375% Senior Notes due 2029, dated as of May 10, 2021, between Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, and Wilmington Trust, National Association, as Trustee
4.92
001-38086
Form 8-K
(filed on May 11, 2021)		4.2—
Form of Rule 144A Global Security for 4.375% Senior Notes due 2029 (included in Exhibit 4.1)
4.93
001-38086
Form 8-K
(filed on May 11, 2021)		4.3—
Form of Regulation S Global Security for 4.375% Senior Notes due 2029 (included in Exhibit 4.1)
4.94
001-38086
Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021)		4.7—
First Supplemental Indenture for the 4.375% Senior Notes due 2029, dated July 29, 2021, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.95
001-38086
Form 10-K (Year ended December 31, 2021) (filed
on February 25, 2022)		4.55—
Second Supplemental Indenture for the 4.375% Senior Notes due 2029, dated December 28, 2021, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
168
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.96
001-38086
Form 10-K (Year ended December 31, 2022) (filed
on March 1, 2023)		4.65—
Third Supplemental Indenture for the 4.375% Senior Notes due 2029, dated December 15, 2022, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.97
001-38086
Form 10-Q (Quarter ended September 30, 2023) (filed on November 7, 2023)		4.5—
Fourth Supplemental Indenture for the 4.375% Senior Notes due 2029, dated July 31, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.98
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
4.94
—
Fifth Supplemental Indenture for 4.375% Senior Notes due 2029, dated October 20, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.99
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.5—
Sixth Supplemental Indenture for 4.375% Senior Notes due 2029, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.100
001-38086
Form 10-Q (Quarter ended March 31, 2025) (filed on May 8, 2025)
4.6
—
Seventh Supplemental Indenture for 4.375% Senior Notes due 2029, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.101
**
—
Eighth Supplemental Indenture for 4.375% Senior Notes, dated as of August 25, 2025, among BlueGen 1 LLC, Vistra Operations Company LLC, the other subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee
4.102
**
—
Ninth Supplemental Indenture for 4.375% Senior Notes, dated as of November 14, 2025, among the Subsidiary Guarantors, Vistra Operations Company LLC, and Wilmington Trust, National Association, as trustee
4.103
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.16—
First Supplemental Indenture, dated as of June 15, 2009, under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009
4.104
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.17—
Second Supplemental Indenture, dated as of June 30, 2009, under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009
4.105
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.18—
Fifth Supplemental Indenture, dated as of August 15, 2016, under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009
4.106
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.19—
Eighth Supplemental Indenture, dated as of August 15, 2016, under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008
4.107
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.20—
Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009
4.108
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.21—
Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008
4.109
001-38086
Form 8-K
(filed on August 23, 2018)		4.7—
Purchase and Sale Agreement dated as of August 21, 2018, between TXU Energy Retail Company LLC as originator, and TXU Energy Receivables Company LLC, as purchaser
169
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.110
001-38086
Form 8-K
(filed on August 23, 2018)		4.8—
Receivable Purchase Agreement dated as of August 21, 2018, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.111
001-38086
Form 8-K
(filed on April 5, 2019)		4.1—
First Amendment to Purchase and Sale Agreement, dated as of April 1, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivables Company LLC, as purchaser
4.112
001-38086
Form 10-Q (Quarter ended June 30, 2019) (filed on August 2, 2019)		4.12—
Second Amendment to Purchase and Sale Agreement, dated as of June 3, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivables Company LLC, as purchaser
4.113
001-38086
Form 8-K
(filed on July 19, 2019)		4.1—
Third Amendment to Purchase and Sale Agreement, dated as of July 15, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivables Company LLC, as purchaser
4.114
001-38086
Form 8-K
(filed on October 16, 2020)		4.1—
Fourth Amendment to Purchase and Sale Agreement, dated as of October 9, 2020, among TXU Energy Retail Company LLC, as an originator and servicer, the other originators named therein, and TXU Energy Receivables Company LLC, as purchaser
4.115
001-38086
Form 8-K
(filed on December 28, 2020)		4.1—
Fifth Amendment to Purchase and Sale Agreement, dated as of December 21, 2020, among TXU Energy Retail Company LLC, certain originators named therein, and TXU Energy Receivables Company LLC, as purchaser
4.116
001-38086
Form of 8-K
(filed on April 9, 2024)		4.2—
Sixth Amendment to Purchase and Sale Agreement, dated as of April 8, 2024, among TXU Receivables, as buyer, TXU Retail, as servicer, certain originators named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.117
001-38086
Form 8-K
(filed on April 5, 2019)		4.2—
First Amendment to Receivables Purchase Agreement, dated as of April 1, 2019, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.118
001-38086
Form 10-Q (Quarter ended June 30, 2019) (filed on August 2, 2019)		4.13—
Second Amendment to Receivables Purchase Agreement, dated as of June 3, 2019, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.119
001-38086
Form 8-K
(filed on July 19, 2019)		4.2—
Third Amendment to Receivables Purchase Agreement, dated as of July 15, 2019, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.120
001-38086
Form 10-K (Year ended December 31, 2022) (filed
on March 1, 2023)		4.76—
Fourth Amendment to Receivables Purchase Agreement, dated as of November 15, 2019, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
170
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.121
001-38086
Form 8-K
(filed on July 16, 2020)		4.1—
Fifth Amendment to Receivables Purchase Agreement, dated as of July 13, 2020, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.122
001-38086
Form 8-K
(filed on October 16, 2020)		4.2—
Sixth Amendment to Receivables Purchase Agreement, dated as of October 9, 2020, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.123
001-38086
Form 8-K
(filed on December 28, 2020)		4.2—
Seventh Amendment to Receivables Purchase Agreement, dated as of December 21, 2020, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.124
001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		4.56—
Eighth Amendment to Receivables Purchase Agreement, dated as of February 19, 2020, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.125
001-38086
Form 10-Q (Quarter ended March 31, 2021) (filed on May 4, 2021)		4.6—
Ninth Amendment to Receivables Purchase Agreement, dated as of March 26, 2021, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.126
001-38086
Form 8-K
(filed on July 15, 2021)		4.1—
Tenth Amendment to Receivables Purchase Agreement, dated as of July 9, 2021, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.127
001-38086
Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021)		4.2—
Eleventh Amendment to Receivables Purchase Agreement, dated as of July 16, 2021, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.128
001-38086
Form of 8-K
(filed on July 15, 2022)		4.1—
Twelfth Amendment to Receivables Purchase Agreement, dated as of July 11, 2022, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator
4.129
001-38086
Form of 8-K
(filed on July 17, 2023)		4.1—
Thirteenth Amendment to Receivables Purchase Agreement, dated as of July 11, 2023, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.130
001-38086
Form of 8-K
(filed on April 9, 2024)		4.1—
Fourteenth Amendment to Receivables Purchase Agreement, dated as of April 8, 2024, among TXU Receivables, as seller, TXU Retail, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
171
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.131
001-38086
Form of 8-K
(filed on July 12, 2024)		4.1—
Fifteenth Amendment to Receivables Purchase Agreement, dated as of July 11, 2024, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.132
001-38086
Form of 8-K
(filed on July 16, 2025)
4.1
—
Sixteenth Amendment to Receivables Purchase Agreement, dated as of July 11, 2025, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.133
001-38086
Form of 8-K
(filed on June 22, 2023)		4.1—
Facility Agreement, dated June 15, 2023, among Palomino Funding Trust I, Vistra Operations Company LLC, the subsidiary guarantors party thereto and Bank of New York Mellon Trust Company, N.A., as senior secured notes trustee
4.134
001-38086
Form of 8-K
(filed on June 22, 2023)		4.2—
Amended and Restated Declaration of Trust of Palomino Funding Trust I, dated June 15, 2023, among Vistra Operations Company LLC, as depositor, The Bank of New York Mellon Trust Company, N.A., as trustee, BNY Mellon Trust of Delaware, as Delaware trustee, and Vistra Operations Company LLC, solely for the purposes of Sections 5.10(b) and (f), Sections 5.17(b), (d), (e) and (f) and Section 10.4(c)
4.135
001-38086
Form of 8-K
(filed on June 22, 2023)		4.3—
Indenture, dated June 15, 2023, between Vistra Operations Company LLC, as issuer, and The Bank of New York Mellon Trust Company, N.A., as trustee
4.136
001-38086
Form of 8-K
(filed on June 22, 2023)		4.4—
Supplemental Indenture, dated June 15, 2023, between Vistra Operations Company LLC, as issuer, the subsidiary guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee
4.137
001-38086
Form of 8-K
(filed on June 22, 2023)		4.5—
Form of 7.233% Senior Secured Notes due 2028 (included in Exhibit 4.4)
4.138
001-38086
Form 10-Q (Quarter ended September 30, 2023) (filed on November 7, 2023)		4.6—
Second Supplemental Indenture for the 7.233% Senior Secured Notes due 2028, dated August 3, 2023, among Vistra Operations Company LLC, as Issuer, the subsidiary guarantors party thereto and the Bank of New York Mellon Trust Company, N.A., as trustee
4.139
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
4.131
—
Third Supplemental Indenture for 7.233% Senior Secured Notes due 2028, dated October 20, 2023, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Bank of New York Mellon Trust Company, N.A., as trustee
4.140
001-38086
Form 10-Q (Quarter ended March 31, 2024) (filed on May 10, 2024)		4.4—
Fourth Supplemental Indenture for 7.233% Senior Secured Notes due 2028, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.141
001-38086
Form 10-Q (Quarter ended March 31, 2025) (filed on May 8, 2025)
4.8
—
Fifth Supplemental Indenture for 7.233% Senior Notes due 2028, dated February 5, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.142
**
—
Sixth Supplemental Indenture for 7.233% Senior Secured Notes due 2028, dated as of August 25, 2025, among BlueGen 1 LLC, Vistra Operations Company LLC, the other subsidiary guarantors party thereto and the Bank of New York Mellon Trust Company, N.A., as trustee
172
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
4.143
**
—
Seventh Supplemental Indenture for 7.233% Senior Secured Notes due 2028, dated as of November 14, 2025, among the Subsidiary Guarantors, Vistra Operations Company LLC, and the Bank of New York Mellon Trust Company, N.A., as trustee
4.144
333-215288
Form S-1
(filed December 23, 2016)
4.1—
Registration Rights Agreement, by and among TCEH Corp. (now known as Vistra Corp.) and the Holders party thereto, dated as of October 3, 2016
4.145
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
4.134
—
Description of Capital Stock
(10)Material Contracts
Management Contracts; Compensatory Plans, Contracts and Arrangements
10.1
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.6—
2016 Omnibus Incentive Plan
10.2
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.7—
Form of Option Award Agreement (Management) for 2016 Omnibus Incentive Plan (pre-2021 awards)
10.3001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		10.5—
Form of Option Award Agreement (Management) for 2016 Omnibus Incentive Plan
10.4001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		10.6—
Form of Restricted Stock Unit Award Agreement (Management) for 2016 Omnibus Incentive Plan (2021)
10.5001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		10.7—
Form of Restricted Stock Unit Award Agreement (Director) for 2016 Omnibus Incentive Plan
10.6001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		10.8—
Form of Performance Stock Unit Award Agreement for 2016 Omnibus Incentive Plan (2021)
10.7
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
10.8
—
Form of Restricted Stock Unit Award Agreement (Management), for 2016 Omnibus Incentive Plan, effective as of January 1, 2025
10.8
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
10.9
—
Form of Performance Stock Unit Award Agreement (Management) for 2016 Omnibus Incentive Plan, effective as of January 1, 2025
10.9
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)
10.10
—
Amended and Restated Vistra Annual Incentive Plan, effective as of January 1, 2025
10.10
001-38086
Form 8-K
(filed on May 23, 2019)		10.1—
Amended and Restated 2016 Omnibus Incentive Plan, effective as of May 20, 2019
10.11
001-38086
Form of 8-K
(filed on May 6, 2024)		10.1—
Amended and Restated 2016 Omnibus Incentive Plan effective as of May 1, 2024
173
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
10.12
001-33443
Form 10-K (Year ended December 31, 2018) (filed on February 28, 2019)
10.7—
Vistra Equity Deferred Compensation Plan for Certain Directors, effective as of January 1, 2019
10.13
001-38086
Form 10-K (Year ended December 31, 2020) (filed
on February 26, 2021)		10.13—
Amendment No. 1 to the Vistra Equity Deferred Compensation Plan, dated effective as of February 24, 2021
10.14
001-38086
Form 10-K (Year ended December 31, 2023) (filed
on February 29, 2024)		10.15—
Second Amended and Restated Employment Agreement, dated March 20, 2022, between James A. Burke and Vistra Corp.
10.15
001-38086
Form 10-K (Year ended December 31, 2023) (filed
on February 29, 2024)		10.16—
Employment Agreement, dated as of July 20, 2022, between Kristopher E. Moldovan, Vistra Corp. and Vistra Corporate Services Company
10.16
001-38086
Form 10-K (Year ended December 31, 2023) (filed
on February 29, 2024)		10.17—
Amended and Restated Employment Agreement, dated as of May 5, 2022, between Stephanie Zapata Moore, Vistra Corp. and Vistra Corporate Services Company
10.17
001-38086
Form 10-K (Year ended December 31, 2023) (filed
on February 29, 2024)		10.18—
Amended and Restated Employment Agreement, dated as of May 5, 2022, between Carrie Lee Kirby, Vistra Corp. and Vistra Corporate Services Company
10.18
001-38086
Form 10-K (Year ended December 31, 2023) (filed
on February 29, 2024)		10.19—
Amended and Restated Employment Agreement, dated as of May 5, 2022, between Scott A. Hudson, Vistra Corp. and Vistra Corporate Services Company
10.19
001-38086
Form 10-K (Year ended December 31, 2023) (filed
on February 29, 2024)		10.21—
Employment Agreement, dated as of August 23, 2022, between Stacey Doré, Vistra Corp. and Vistra Corporate Services Company
10.20
001-38086
Form 10-K (Year ended December 31, 2022) (filed
on March 1, 2023)		10.22—
Form of indemnification agreement with directors and officers
10.21
001-38086
Form 8-K
(filed on May 5, 2025)
10.1
—
2025 Employee Stock Purchase Plan, effective April 30, 2025
Credit Agreements and Related Agreements
10.22
333-215288
Form S-1
(filed December 23, 2016)
10.1—
10.23
333-215288
Form S-1
(filed December 23, 2016)
10.2—
Amendment to Credit Agreement, dated December 14, 2016, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.24
333-215288
Amendment No. 1
to Form S-1
(filed February 14, 2017)
10.3—
Second Amendment to Credit Agreement, dated February 1, 2017, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.25
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.4—
Third Amendment to Credit Agreement, dated February 28, 2017, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
174
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
10.26
001-38086
Form 8-K
(filed August 17, 2017)
10.1—
Fourth Amendment to Credit Agreement, dated as of August 17, 2017 (effective August 17, 2017), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.27
001-38086
Form 8-K
(filed December 14, 2017)
10.1—
Fifth Amendment to Credit Agreement, dated as of December 14, 2017 (effective December 14, 2017), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.28
001-38086
Form 8-K
(filed February 22, 2018)
10.1—
Sixth Amendment to Credit Agreement, dated as of February 20, 2018 (effective February 20, 2018), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.
10.29
001-38086
Form 8-K
(filed June 15, 2018)
10.1—
Seventh Amendment to Credit Agreement, dated as of June 14, 2018, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties party thereto, Credit Suisse and Citibank, N.A. as the 2018 Incremental Term Loan Lenders, the various other Lenders party thereto, Credit Suisse as Successor Administrative Agent and as Successor Collateral Agent, and Delaware Trust Company, as Collateral Trustee.
10.30
001-38086
Form 8-K
(filed April 4, 2019)
10.4—
Eighth Amendment to Credit Agreement, dated March 29, 2019, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties (as defined in the Vistra Operations Credit Agreement) party thereto, Bank of Montreal, Chicago Branch, as new Revolving Loan Lender, Revolving Letter of Credit Issuer and Joint Lead Arranger, the various other Lenders and Letter of Credit Issuers party thereto, and Credit Suisse as Administrative Agent and Collateral Agent
10.31
001-38086
Form 8-K
(filed May 29, 2019)
10.1—
Ninth Amendment to Credit Agreement, dated May 29, 2019, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties (as defined in the Vistra Operations Credit Agreement) party thereto, Sun Trust Bank, as incremental Revolving Loan Lender, and Credit Suisse AG, Cayman Island Branch, as Administrative Agent and Collateral Agent
10.32
001-38086
Form 8-K (filed
on November 21, 2019)		10.1—
Tenth Amendment to the Credit Agreement, dated November 15, 2019, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party thereto, the other Credit Parties (as defined in the Credit Agreement) party thereto, Credit Suisse AG, Cayman Islands Branch (as the 2019 Incremental Term Loan Lender and as Administrative Agent and as Collateral Agent), and the other Lenders party thereto
10.33
001-38086
Form 8-K (filed
on May 5, 2022)		10.1—
Eleventh Amendment to the Credit Agreement, dated April 29, 2022, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party thereto, the other Credit Parties (as defined in the Credit Agreement) party thereto, the financial institutions providing 2022 New Revolving Credit Commitments (as defined in the Credit Agreement), the Revolving Credit Lenders providing 2022 Extended Revolving Credit Commitments (as defined in the Credit Agreement), the Revolving Letter of Credit Issuers (as defined in the Credit Agreement) party thereto, and Credit Suisse AG, Cayman Islands Branch (as Administrative Agent and as Collateral Agent)
175
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
10.34
001-38086
Form 10-Q (Quarter ended September 30, 2022) (filed on November 4, 2022)		10.3—
Twelfth Amendment to the Credit Agreement, dated July 18, 2022, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party thereto, financial institutions, Revolving Credit Lenders, and Revolving Letter of Credit Issuers (in each case as defined in the Credit Agreement) party thereto, and Credit Suisse AG, Cayman Islands Branch (as Administrative Agent and as Collateral Agent)
10.35
001-38086
Form 10-Q (Quarter ended June 30, 2023) (filed on August 9, 2023)		10.1—
Thirteenth Amendment to the Credit Agreement, dated April 28, 2023, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party thereto, financial institutions, Revolving Credit Lenders, and Revolving Letter of Credit Issuers (in each case as defined in the Credit Agreement) party thereto, and Credit Suisse AG, Cayman Islands Branch (as Administrative Agent and as Collateral Agent)
10.36
001-38086
Form 10-Q (Quarter ended September 30, 2023) (filed on November 7, 2023)		10.1—
Fourteenth Amendment to the Credit Agreement, dated September 26, 2023, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party thereto, financial institutions, Revolving Credit Lenders, and Revolving Letter of Credit Issuers (in each case as defined in the Credit Agreement) party thereto, and Credit Suisse AG, Cayman Islands Branch (as Administrative Agent and as Collateral Agent)
10.37
001-38086
Form 8-K (filed
on December 26, 2023)		10.1—
Fifteenth Amendment to the Credit Agreement, dated December 20, 2023, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the 2023 Incremental Term Loan Lender, the other Credit Parties (as defined in the Credit Agreement) party thereto, the other lenders party thereto, and Credit Suisse AG, Cayman Islands Branch (as Administrative Agent and as Collateral Agent)
10.38
001-38086
Form 10-Q (Quarter ended September 30, 2024) (filed on November 8, 2024)		10.6—
Sixteenth Amendment to the Credit Agreement, dated October 11, 2024, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the guarantors party thereto, the revolving credit lenders and revolving letter of credit issuers party thereto, and Citibank, N.A. (as Administrative Agent and as Collateral Agent)
10.39
001-38086
Form 8-K
(filed on December 16, 2024)
10.1—
Seventeenth Amendment to Credit Agreement, dated December 10, 2024, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party thereto, the lenders party thereto, and Citibank, N.A. (as Administrative Agent and Collateral Agent)
10.40
001-38086
Form 8-K
(filed on April 9, 2018)
10.10—
Assumption Agreement, dated as of April 9, 2018, between Vistra Energy Corp. (now known as Vistra Corp.) (as successor by merger to Dynegy Inc.), and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and as Collateral Trustee.
10.41
001-38086
Form 8-K
(filed on April 9, 2018)
10.11—
Guarantee and Collateral Agreement, dated as of April 23, 2013, among Dynegy Inc., the subsidiaries of the borrower from time to time party thereto and Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013).
10.42
001-38086
Form 8-K
(filed on April 9, 2018)
10.12—
Joinder, dated as of April 9, 2018, among Vistra Energy Corp. (now known as Vistra Corp.), the subsidiary guarantors party thereto and Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee.
176
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
10.43
001-38086
Form 8-K
(filed on April 9, 2018)
10.13—
Collateral Trust and Intercreditor Agreement, dated as of April 23, 2013 among Dynegy, the Subsidiary Guarantors (as defined therein), Credit Suisse AG, Cayman Islands Branch and each person party thereto from time to time (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013).
10.44
001-38086
Form 10-K (Year ended December 31, 2021) (filed
on February 25, 2022)		10.63—
Credit Agreement, dated as of February 4, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.45
001-38086
Form 10-Q (Quarter ended June 30, 2022) (filed on August 5, 2022)		10.3—
First Amendment to Credit Agreement, dated as of May 5, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.46
001-38086
Form 10-Q (Quarter ended June 30, 2022) (filed on August 5, 2022)		10.4—
Second Amendment to Credit Agreement, dated as of May 26, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.47
001-38086
Form 10-Q (Quarter ended June 30, 2022) (filed on August 5, 2022)		10.5—
Third Amendment to Credit Agreement, dated as of June 8, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.48
001-38086
Form 10-K (Year ended December 31, 2022) (filed
on March 1, 2023)		10.72—
Fourth Amendment to Credit Agreement, dated as of October 5, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.49
001-38086
Form 10-K (Year ended December 31, 2022) (filed
on March 1, 2023)		10.73—
Fifth Amendment to Credit Agreement, dated as of October 21, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.50
001-38086
Form 10-Q (Quarter ended September 30, 2023) (filed on November 7, 2023)		10.2—
Sixth Amendment to Credit Agreement, dated as of September 26, 2023, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.51
001-38086
Form 10-Q (Quarter ended September 30, 2023) (filed on November 7, 2023)		10.3—
Seventh Amendment to Credit Agreement, dated as of October 4, 2023, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.52
001-38086
Form 10-Q (Quarter ended September 30, 2024) (filed on November 8, 2024)		10.5—
Eighth Amendment to Credit Agreement, dated as of October 2, 2024, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.53
001-38086
Form 8-K
(filed on October 6, 2025)
10.1—
Ninth Amendment to Credit Agreement, dated as of October 1, 2025, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.54
001-38086
Form 8-K
(filed on April 1, 2024)		10.1—
Credit Agreement, dated March 26, 2024, by and among Vistra Zero Operating Company, LLC, the Lenders (as defined in the Credit Agreement) party thereto and Citibank, N.A. (as Administrative Agent and as Collateral Agent)
177
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
10.55
001-38086
Form 8-K
(filed on December 19, 2024)		10.1—
First Amendment to Credit Agreement, dated December 17, 2024, by and among Vistra Zero Operating Company, LLC, the guarantors party thereto, the lenders party thereto and Citibank, N.A. (as Administrative Agent and Collateral Agent)
Other Material Contracts
10.56
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.5—
Collateral Trust Agreement, dated as of October 3, 2016, by and among TEX Operations Company LLC (now known as Vistra Operations LLC), the Grantors from time to time thereto, Railroad Commission of Texas, as first-out representative, and Deutsche Bank AG, New York Branch, as senior credit agreement representative
10.57
001-38086
Form 8-K
(filed on June 15, 2018)		10.2—
Amendment to Collateral Trust Agreement, effective as of June 14, 2018, among Vistra Operations Company LLC, the other Grantors from time to time party thereto, Railroad Commission of Texas, as first-out representative, and Credit Suisse AG, Cayman Islands Branch, as senior credit agreement agent, and Delaware Trust Company, as Collateral Trustee
10.58
001-38086
Form 8-K
(filed on June 15, 2018)		10.3—
Collateral Trust Joinder, dated June 14, 2018, between the Additional Grantors party thereto and Delaware Trust Company, as Collateral Trustee, to the Collateral Trust Agreement, effective pursuant to the Seventh Amendment as of June 14, 2018, among Vistra Operations Company LLC, the other Grantors from time to time party thereto, Railroad Commission of Texas, as First-Out Representative, Credit Suisse AG, Cayman Islands Branch, as Senior Credit Agreement Agent, and Delaware Trust Company, as Collateral Trustee.
10.59
001-38086
Form 8-K
(filed on January 4, 2024)		10.1—
Amended and Restated Tax Receivable Agreement, dated December 29, 2023, by and between the Company and Equiniti Trust Company, LLC
10.60
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.14—
Tax Matters Agreement, by and among TEX Energy LLC (now known as Vistra Corp.), EFH Corp., Energy Future Intermediate Holding Company LLC, EFI Finance Inc. and EFH Merger Co. LLC, dated as of October 3, 2016
10.61
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
10.18—
Amended and Restated Split Participant Agreement, by and between Oncor Electric Delivery Company LLC (f/k/a TXU Electric Delivery Company) and TEX Operations Company LLC (now known as Vistra Operations Company LLC), dated as of October 3, 2016
10.62
001-38086
Form 8-K
(filed on October 16, 2020)		10.1—
10.63
001-38086
Form 8-K
(filed on July 15, 2021)		10.1—
Amendment No. 1 to Master Framework Agreement, dated as of July 1, 2021, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer
10.64
001-38086
Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021)		10.2—
Amendment No. 2 to Master Framework Agreement, dated as of August 3, 2021, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer
10.65
001-38086
Form 8-K
(filed on July 15, 2022)		10.1—
Amendment No. 3 to Master Framework Agreement, dated as of July 11, 2022, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer
178
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
10.66
001-38086
Form 8-K
(filed on July 17, 2023)		10.1—
Amendment No. 4 to Master Framework Agreement, dated as of July 11, 2023, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators name therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer
10.67
001-38086
Form 8-K
(filed on July 12, 2024)		10.1—
Amendment No. 5 to Master Framework Agreement, dated as of July 11, 2024, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators name therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer
10.68
001-38086
Form of 8-K
(filed on July 16, 2025)		10.1—
Amendment No. 6 to Master Framework Agreement, dated as of July 11, 2024, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer
10.69
001-38086
Form 8-K
(filed on October 16, 2020)		10.2—
Master Repurchase Agreement, dated as of October 9, 2020, between TXU Energy Retail Company LLC and MUFG Bank, Ltd.
10.70
001-38086
Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021)		10.3—
Amendment No. 1 to Master Repurchase Agreement, dated as of August 3, 2021, between TXU Energy Retail Company LLC and MUFG Bank, Ltd.
10.71
001-38086
Form 8-K
(filed on December 28, 2020)		10.1—
Joinder Agreement, dated as of December 21, 2020, among TXU Energy Retail company LLC, as seller party agent, Vistra Operations Company LLC, as guarantor, certain originators named therein, and MUFG Bank, Ltd., as buyer
10.72
001-38086
Form 10-K (Year ended December 31, 2021) (filed
on February 25, 2022)		10.62—
Amendment No. 2 to Master Repurchase Agreement, dated as of December 30, 2021, between TXU Energy Retail Company LLC and MUFG Bank, Ltd.
10.73
001-38086
Form 8-K
(filed on July 17, 2023)		10.2—
Amendment No. 3 to Master Repurchase Agreement, dated as of July 11, 2023, by and among TXU Energy Retail Company LLC, as seller and MUFG Bank, Ltd., as buyer
10.74
001-38086
Form 8-K
(filed on April 9, 2024)		10.1—
Joinder Agreement, dated as of April 8, 2024, among TXU Retail, as seller party agent, Vistra Operations, as guarantor, certain originators named therein, and MUFG, as buyer
10.75
001-38086
Form 8-K
(filed on July 12, 2024)		10.2—
Amendment No. 4 to Master Repurchase Agreement, dated as of July 11, 2024, by and among TXU Energy Retail Company LLC, as seller and MUFG Bank, Ltd., as buyer
10.76
001-38086
Form 10-K (Year ended December 31, 2024) (filed
on February 28, 2025)		10.76—
Amended and Restated Class B Unit Purchase Agreement, dated December 11, 2024, by and among Vistra Operations Company LLC, Vistra Vision Holdings I LLC, and Nuveen Asset Management, LLC
(19)Insider Trading Policy
19.1
**
—
Transactions in Vistra Corp. Securities Policy
(21)Subsidiaries of the Registrant
21.1**—
(23)Consent of Experts
23.1**—
(31)Rule 13a-14(a) / 15d-14(a) Certifications
179
VISTRA CORP.
ExhibitsPreviously Filed With File Number*As
Exhibit
31.1**—
Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2**—
Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32)Section 1350 Certifications
32.1***—
Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2***—
Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(95)Mine Safety Disclosures
95.1**—
(97)Policy Relating to Recover of Erroneously Awarded Compensation
97.1001-38086
Form 10-K (Year ended December 31, 2023) (filed
on February 29, 2024)		97.1—
XBRL Data Files
101.INS**—
The following financial information from Vistra Corp.'s Annual Report on Form 10-K for the period ended December 31, 2025 formatted in Inline XBRL (Extensible Business Reporting Language) includes: (i) the Consolidated Statements of Operations, (ii) the Consolidated Statements of Comprehensive Income (Loss), (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statement of Changes in Equity and (vi) the Notes to the Consolidated Financial Statements.
101.SCH**—XBRL Taxonomy Extension Schema Document
101.CAL**—XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**—XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**—XBRL Taxonomy Extension Label Linkbase Document
101.PRE**—XBRL Taxonomy Extension Presentation Linkbase Document
104—The Cover Page Interactive Data File does not appear in Exhibit 104 because its XBRL tags are embedded within the Inline XBRL document.
____________________
*    Incorporated herein by reference
**    Filed herewith
***    Furnished herewith


Item 16.FORM 10-K SUMMARY

None.

180

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Vistra Corp. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VISTRA CORP.
Date:February 26, 2026By/s/ JAMES A. BURKE
James A. Burke (President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Vistra Corp. and in the capacities and on the date indicated.
SignatureTitleDate
/s/ JAMES A. BURKEPrincipal Executive Officer and DirectorFebruary 26, 2026
(James A. Burke, President and Chief Executive Officer)
/s/ KRISTOPHER E. MOLDOVANPrincipal Financial OfficerFebruary 26, 2026
(Kristopher E. Moldovan, Chief Financial Officer)
/s/ MARGARET MONTEMAYORPrincipal Accounting OfficerFebruary 26, 2026
(Margaret Montemayor, Senior Vice President and Chief Accounting Officer)
/s/ SCOTT B. HELMChairman of the Board and DirectorFebruary 26, 2026
(Scott B. Helm, Chairman of the Board)
/s/ HILARY E. ACKERMANNDirectorFebruary 26, 2026
(Hilary E. Ackermann)
/s/ ARCILIA C. ACOSTADirectorFebruary 26, 2026
(Arcilia C. Acosta)
/s/ GAVIN R. BAIERADirectorFebruary 26, 2026
(Gavin R. Baiera)
/s/ PAUL M. BARBASDirectorFebruary 26, 2026
(Paul M. Barbas)
/s/ LISA CRUTCHFIELDDirectorFebruary 26, 2026
(Lisa Crutchfield)
/s/ JULIE A. LAGACYDirectorFebruary 26, 2026
(Julie A. Lagacy)
/s/ JOHN W. PITESADirectorFebruary 26, 2026
(John W. Pitesa)
/s/ JOHN R. SULTDirectorFebruary 26, 2026
(John R. Sult)
/s/ ROBERT C. WALTERSDirectorFebruary 26, 2026
(Robert C. Walters)

181

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