What changed in this filing

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Item 1. Business

2026-02-27 compared with 2025-02-28 · 179 added, 228 removed, 342 unchanged (54% of the section changed)

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See Glossary of Terms and Abbreviations for defined terms.

Vistra is an integrated retail electricity and power generation company.

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.

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Market Discussion

The operations of Vistra, as an integrated retail electricity and power generation company, are further aligned into five reportable business segments:

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 plants and mines.

In the fourth quarter of 2024, we updated our reportable segments to reflect changes in how the Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance, and allocates resources by eliminating 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 geography.

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

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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, and U.S.

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.

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Electricity Generation Operations

Vistra is the largest competitive power generator in the U.S.

Vistra is one of the largest competitive power generators in the U.S.

as measured by MWh of generation capacity.

At December 31, 2024, our generating capacity was powered by the following:

At December 31, 2025, our generating capacity was powered by the following fuels and technologies:

Primary Fuel Technology Net Capacity (MW) % of Net Capacity

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Coal ST 8,743 20%

Nuclear 6,448 16%

Uranium Nuclear 6,448 15%

Renewable Solar/Battery 1,274 3%

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

Net Capacity (MW) Refueling Outage Frequency

License Expiration Date

Comanche Peak Unit 1

1,200 18 Months

Comanche Peak Unit 2

1,200 18 Months

Beaver Valley Unit 1

939 18 Months 2036

Beaver Valley Unit 2

933 18 Months 2047

1,268 24 Months

908 24 Months

(a) In 2023, an application for a license renewal at our Perry nuclear plant was filed with the NRC to extend our license through 2046.

Unit ISO Net Capacity (MW) Refueling Outage Frequency License Expiration Date

Comanche Peak Unit 1 ERCOT 1,200 18 Months 2050

Comanche Peak Unit 2 ERCOT 1,200 18 Months 2053

Beaver Valley Unit 1 PJM 939 18 Months 2036

Beaver Valley Unit 2 PJM 933 18 Months 2047

Perry PJM 1,268 24 Months 2046

Davis-Besse PJM 908 24 Months 2037

Nuclear units are generally operated at full capacity.

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During a refueling outage, other maintenance, modification, and testing activities are completed that cannot be accomplished when the unit is in operation.

We have contracts in place for all of our nuclear fuel requirements through 2029.

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 monitor developments regarding the availability of nuclear fuel that may arise out of the Russia and Ukraine conflict.

Management's Discussion and Analysis of Financial Condition, and Results of Operations – Significant Activities and Events, and Items Influencing Future Performance – Macroeconomic Conditions .

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:

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Total 43,641 100%

Wholesale Operations — Our wholesale commodity risk management group is responsible for dispatching our generation fleet in response to market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleet production with our retail customer and wholesale sales opportunities.

Market demand, also known as load, faced by electric power systems, such as those we operate in, varies from moment to moment as a result of changes in business and residential demand, which is often driven by weather.

Unlike most other commodities, the production and consumption of electricity must remain balanced on an instantaneous basis.

There is a certain baseline demand for electricity across an electric power system that occurs throughout the day, which is typically satisfied by baseload generation units with low variable operating costs.

Baseload generation units can also increase output to satisfy certain incremental demand and reduce output when demand is unusually low.

Intermediate/load-following generation units, which can more efficiently change their output to satisfy increases in demand, typically satisfy a large proportion of changes in intraday load as they respond to daily increases in demand or unexpected changes in supply created by reduced generation from renewable resources or other generator outages.

Peak daily loads may be satisfied by peaking units.

Peaking units are typically the most expensive to operate, but they can quickly start up and shut down to meet brief peaks in demand.

In general, baseload units, intermediate/load following units, and peaking units are dispatched into the ISO/RTO grid in order from lowest to highest variable cost.

Price formation is typically based on the highest variable cost unit that clears the market to satisfy system demand at a given point in time.

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.

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They impose bid and price limits in wholesale power markets.

NERC regions 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.

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.

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Generators receive the location-based marginal price for their output.

ERCOT — ERCOT is an ISO that manages the flow of electricity from approximately 103,600 MW of expected Summer 2024 peak generation capacity to approximately 27 million Texas customers, representing approximately 90% of the state's electric load.

As an energy-only market, ERCOT's market design is distinct from other competitive electricity markets in the U.S.

Other markets maintain a minimum planning reserve margin through regulated planning, resource adequacy requirements and/or capacity markets.

In contrast, ERCOT's resource adequacy is currently predominately dependent on energy-market price signals.

The Texas Legislature mandated the development of an ancillary service, the Dispatchable Reliability Reserve Service (DRRS), to address intra-hour operations challenges.

The PUCT voted in December 2024 to have ERCOT develop DRRS so it can address both operational issues and resource adequacy issues.

ERCOT is continuing work on DRRS, and it has not been implemented as of the date hereof.

In 2014, ERCOT implemented the Operating Reserve Demand Curve (ORDC), pursuant to which wholesale electricity prices in the real-time electricity market increase automatically as available operating reserves decrease below defined threshold levels, creating a price adder.

The slope of the ORDC curve is determined through a mathematical loss of load probability calculation using forecasted reserves and historical data.

In both March 2019 and March 2020, ERCOT implemented 0.25 standard deviation shifts in the loss of load probability calculation and moved to using a single blended ORDC curve;

these changes resulted in a more rapid escalation in power prices as operating reserves fall below defined thresholds.

Effective January 1, 2022, when operating reserves drop to 3,000 MW or less, the ORDC automatically adjusts power prices to $5,000/MWh which is equal to the high system-wide offer cap.

When ERCOT implements real-time co-optimization, discussed below, the ORDC will be replaced by ancillary service demand curves that are designed to mimic the operation of the ORDC.

ERCOT also calculates the "peaker net margin" based on revenues a hypothetical unhedged peaking unit would collect in the market.

If the peaker net margin exceeds a certain threshold, the system-wide offer cap is reduced to the low system-wide offer cap of $2,000/MWh for the remainder of the calendar year.

In December 2023, the PUCT also 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.

Historically, high demand due to elevated temperatures in the summer months or high demand due to reduced temperatures in the winter months, combined with underperformance of wind generation, has created the conditions during which the ORDC contributes meaningfully to power prices.

Extreme weather conditions can also lead to scarcity conditions regardless of season.

Other than during periods of "scarcity pricing," the price of power is typically set by natural gas-fueled generation facilities (see Item 7.

Management's Discussion and Analysis of Financial Condition, and Results of Operations – Significant Activities and Events, and Items Influencing Future Performance ).

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:

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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 is dispatched and priced in five-minute intervals.

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.

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These two markets allow market participants to manage their risk profile by adjusting their participation in each market.

In addition, ERCOT uses ancillary services to maintain system reliability, including regulation service, responsive reserve service, and non-spinning reserve service.

Ancillary services are provided by generators and qualified loads to help maintain the stable voltage and frequency requirements of the transmission system.

ERCOT currently procures ancillary services in the day-ahead market, but plans to implement co-optimization of energy and ancillary services in the real-time market by the end of 2025.

Because ERCOT has one of the highest concentrations of wind and solar capacity generation among U.S.

markets, the ERCOT market is more susceptible to fluctuations in wholesale electricity supply due to intermittent wind and solar production, making ERCOT more vulnerable to periods of generation scarcity.

ERCOT implemented the ERCOT Contingency Reserve Service (ECRS) in June 2023 to further address the need for operating reserves to manage load and intermittent resource output uncertainty.

PJM — PJM is an RTO that manages the flow of electricity from approximately 183,000 MW of generation capacity to approximately 65 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.

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.

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.

We have participated in RPM auctions for years up to and including PJM's planning year 2025-2026, which ends May 31, 2026.

PJM's RPM auction for planning year 2026-2027 was delayed and is expected to be run in July 2025.

We also enter into bilateral capacity transactions.

PJM's Capacity Performance (CP) rules were designed to improve system reliability and include penalties for under-performing units and reward for over-performing units during shortage events.

Full transition of the capacity market to CP rules occurred in planning year 2020-2021.

An independent market monitor continually monitors PJM markets to ensure a robust, competitive market and to identify improper behavior by any entity.

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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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 and fuel supply.

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.

ISO-NE is working with stakeholders to transition to a prompt capacity market for the delivery year starting in June 2028.

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.

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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, our Independence facility sells a significant portion of its capacity through bilateral transactions.

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.

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Energy prices vary among the regional zones and locations in MISO and are largely influenced by transmission constraints and fuel supply.

An independent market monitor is responsible for evaluating the performance of the markets and identifying conduct by market participants or MISO that may compromise the efficiency or distort the outcome of the markets.

MISO administers a one-year Planning Resource Auction (PRA) for the next planning year from June 1st of the current year to May 31st of the following year.

MISO's PRA currently uses a vertical demand curve that can result in more volatile capacity prices.

In 2022, FERC approved MISO's proposal to change the annual Planning Resource Auction into a seasonal auction, effective for the 2023-2024 planning year.

Starting with the PRA for the 2025-2026 planning year, MISO will begin using a sloped demand curve.

We participate in these auctions with open capacity that has not been committed through bilateral or retail transactions.

We also participate in the MISO annual and monthly financial transmission rights auctions to manage the cost of our transmission congestion, as measured by the congestion component of the LMP price differential between two points on the transmission grid across the market area.

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.

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Unlike other centrally cleared capacity markets, the resource adequacy markets in California are primarily bilaterally traded markets.

In 2020, the CPUC introduced a central procurement entity for Local RA Capacity effective for the 2023 compliance year.

The central procurement entity runs a pay-as-bid auction for Local RA Capacity.

In November 2016, CAISO implemented a voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the market.

The voluntary Competitive Solicitation Process, which FERC approved in October 2015, is a modification to the Capacity Procurement Mechanism (CPM) and provides another avenue to sell RA capacity.

Unlike most other commodities, the production and consumption of electricity must remain balanced on an instantaneous basis.

Baseload generation units can also increase output to satisfy certain incremental demand and reduce output when demand is unusually low.

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.

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.

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).

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.

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Business Strategy

Vistra is the largest producer of power in deregulated markets in the U.S.

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.

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• We do business the right way.

Every decision we make and action we take will be evidence of the utmost integrity and compliance.

• We compete to win.

We will create the leading integrated energy company with an unmatched work ethic, an analysis-driven and disciplined culture with strong leadership and decision-making throughout the organization.

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 are committed to each other, everything we do and to the success of our company.

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 respect our fellow employees, we focus on our customers, and we care about our communities where we live and do business.

We will maintain productive and respectful relationship with our legislators, regulators and community leaders.

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:

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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.

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Human Capital Resources

Vistra's approach to human capital management is guided by our core values.

Our core values 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 values, which serve as the cultural foundation of the Company.

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.

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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 Casco Bay, Forney, Lamar, and Liberty generation facilities completed reevaluations and were recommended to continue as VPP Star in 2024.

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.

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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.

We recognize the value of having an inclusive workforce.

Our employees reflect the communities we serve, ranging in age, gender, ethnicity, physical appearance, thoughts, styles, religions, nationality, education and numerous other traits.

Creating and maintaining an environment where our employees feel appreciated for their talent and contribution enhances our ability to recruit and retain the best talent in the marketplace and to provide a work environment that allows all employees to continue to be their best.

Vistra is active in our communities through employee-led initiatives, business teams, and collaborations with many community agencies, such as United Way.

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.

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.

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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 2024, Vistra began including the former Energy Harbor employees and leaders in leadership and front-line training programs to accelerate the integration of Vistra's culture with the new nuclear sites.

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.

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Over 260 employees participated in 2025.

In 2024, Vistra launched physical and online Career Hubs, where employees can go to learn about a wide variety of careers within the company and identify skills they need to develop to pursue those roles.

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.

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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 six locations.

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.

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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 policy goals, and develop an action plan within 30 days to resolve any policy inconsistencies.

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.

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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.

Risk Factors and Note 18 to the Financial Statements for additional information.

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We estimate that our generation facilities produced approximately 102 million short tons of CO 2 in the year ended 2025.

Vistra's carbon intensity for power generation improved from 0.56 short tons of CO 2 per MWh in 2023 to 0.48 short tons of CO 2 per MWh in 2024, a 15% year-over-year improvement driven by our Energy Harbor acquisition.

Vistra's carbon intensity for power generation improved from 0.48 short tons of CO 2 per MWh in 2024 to 0.47 short tons of CO 2 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 CO 2 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 50% reduction in carbon dioxide (CO 2 ) emissions, a 66% reduction in nitrogen oxide (NO X ) emissions, and an 90% reduction in sulfur dioxide (SO 2 ) emissions through year-end 2024, compared to a 2010 baseline.

Since 2010, Vistra has retired more than 15,100 MW of coal and natural gas power plants resulting in a 46% reduction in CO 2 emissions, a 64% reduction in NO X emissions, and an 88% reduction in sulfur dioxide (SO 2 ) emissions through year-end 2025, compared to a 2010 baseline.

Vistra also has targets validated through the Science Based Targets initiative (SBTi).

Our near-term science-based 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.

Vistra is exploring multiple options to meet these targets, but we must balance these efforts with the need to prioritize reliability and affordability for our customers.

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.

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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 4,048 MW of nuclear generation facilities in PJM from Energy Harbor.

• Re-powered generation assets — In May 2024, we announced our intention to repower the coal-fueled Coleto Creek Power Plant near Goliad, Texas as a natural-gas fueled plant with up to 600 MW of capacity.

• Uprated capacity at existing natural gas plants — Additional capacity has been added to existing natural gas plants through technological upgrades improving efficiency and overall fleet intensity.

• 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 at retired or to-be-retired plant sites 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.

• 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 Texas, with expected commercial operation dates beginning in 2025, and additional solar generation facilities at retired or to-be retired plant sites in Illinois with expected commercial operation dates beginning in 2026.

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.

Green Finance Framework

In December 2021, we announced the publication of our Green Finance Framework, which allows us to issue green financial instruments to fund new or existing projects that support renewable energy and energy efficiency with alignment to our ESG strategy.

Greenhouse Gas Emissions (GHG)

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The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing.

Starting in 2030, the rule would begin to require more CO 2 emissions control at certain existing fossil fuel-fired steam generating units, with more stringent standards beginning in 2032 for coal-fired units that plan to operate for a longer period of time.

For new natural gas combustion turbines that operate more frequently, the rule would phase in increasingly stringent CO 2 requirements over time.

Under the rule, states would be required to submit plans to the EPA within 24 months of the rule's publication in the Federal Register that provide for the establishment, implementation, and enforcement of standards of performance for existing sources.

These state plans must generally establish standards that are at least as stringent as the EPA's emission guidelines.

Under the rule, existing coal-fired steam generation units that will operate on or after January 1, 2039 must start complying with their standards of performance (based on application of CCS with 90 percent capture) by January 1, 2032.

Units that are permanently retiring before January 1, 2039, but after December 31, 2031, must start complying with their standards of performance (based on co-firing with 40 percent natural gas on a heat input basis) beginning on January 1, 2030.

Units permanently retiring by January 1, 2032 are exempt from the rule.

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None of our existing large or small combustion turbines are subject to this rule.

The rule also regulates any new gas units.

For new combustion turbine units, the rule establishes three different categories depending on how intensively those units are operated, with immediate compliance obligations for all three categories but more stringent standards beginning in 2032 only for the category of units operating the most intensively.

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.

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We are participating in an industry coalition challenging the rule.

In July 2024, the D.C.

Circuit Court denied the motions to stay and a number of parties subsequently filed an emergency request with the U.S.

Supreme Court to stay the rule which was denied in October 2024.

Oral argument on the merits of the legal challenges to the rule was held in December 2024 before the D.C.

Circuit Court.

In February 2025, the D.C.

Circuit granted the unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

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

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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 December 2017, the RGGI states released an updated model rule with changes to the CO 2 budget trading program, including an additional 30 percent reduction in the CO 2 annual cap by the year 2030, relative to 2020 levels.

RGGI is currently conducting its third program review which may include an updated model rule.

Our generation facilities in Connecticut, Maine, Massachusetts, New Jersey, New York and Virginia emitted approximately 11 million short tons of CO 2 during 2024.

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 CO 2 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 CO 2 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.

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The program is based on the RGGI proposed 2017 model rule and linked Virginia to RGGI in 2021.

The Governor of Virginia issued an executive order in January 2022 to begin the process of removing the state from RGGI.

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.

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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.

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Pennsylvania — In April 2022, the Pennsylvania Environmental Quality Board finalized regulations that would establish Pennsylvania's participation in RGGI.

In July 2022, the Commonwealth Court of Pennsylvania (Commonwealth Court) took action to uphold a preliminary injunction over Pennsylvania's RGGI regulations.

The Pennsylvania Supreme Court denied a request for emergency relief from the injunction in August 2022.

In November 2023, the Commonwealth Court found that Pennsylvania cannot join RGGI without legislative approval and enjoined the Pennsylvania Department of Environmental Protection from implementing RGGI.

The state has appealed this decision to the Pennsylvania Supreme Court where it is still pending.

The Pennsylvania Department of Environmental Protections has indicated it will not seek to implement RGGI until the Pennsylvania Supreme Court acts.

As a result, RGGI is not being implemented or enforced in Pennsylvania at this time.

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.

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Circuit Court's 2019 ruling.

Vistra subsidiaries filed comments on that rulemaking in December 2020, and the EPA published a final rule in the Federal Register on April 30, 2021 that reduces ozone season NO X budgets in certain states.

The EPA published a final rule in the Federal Register on April 30, 2021 that reduces ozone season NO X budgets in certain states.

We do not believe that the final rule causes a material adverse impact on our future financial results.

In October 2015, the EPA revised the primary and secondary ozone NAAQS to lower the 8-hour standard for ozone emissions during ozone season (May to September).

As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS.

In February 2023, the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain trade groups, and others challenged that disapproval in the U.S.

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 2023, those same parties filed motions to stay the EPA's SIP disapproval in the Fifth Circuit Court, and the EPA moved to transfer our challenges to the D.C.

Circuit Court or have those challenges dismissed.

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.

We, along with many other companies, trade groups, states and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions.

In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP).

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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.

Texas would be moved into the revised (and more restrictive) Group 3 trading program previously established in the Revised CSAPR Update Rule that includes emission budgets for 2023 that the EPA says are achievable through existing controls installed at power plants.

Allowances will be limited under the program and will be further reduced beginning in ozone season 2026 to a level that is intended to reduce operating time of coal-fueled power plants during ozone season or force coal plants to retire, particularly those that do not have selective catalytic reduction systems such as our Martin Lake power plant.

In May 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a decision on the merits and denied the EPA's motion to transfer our challenge to the D.C.

Circuit Court.

As a result of the stay, we do not believe the EPA has authority to implement the GNP FIP as to Texas sources pending the resolution of the merits, meaning that Texas will remain in Group 2 and not be subject to any requirements under the GNP FIP at least until the Fifth Circuit Court rules on the merits.

Oral argument was heard in December 2023 before the Fifth Circuit Court.

In June 2023, the EPA published the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the Fifth Circuit Court.

In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the GNP FIP in the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court.

After the motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the GNP FIP as to Texas is stayed.

In February 2025, the Department of Justice filed a motion on behalf of the EPA in the Fifth Circuit Court, 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 February 2025, the State of Texas filed a response opposing the requested abatement, which we joined.

In July 2023, the Fifth Circuit Court ruled that the GNP FIP challenge would be held in abeyance pending the resolution of the litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay.

In a related action brought by other states and parties challenging the GNP FIP, in June 2024, the U.S.

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.

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As a result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP.

In February 2025, the D.C.

Circuit Court denied a motion filed by the Department of Justice on behalf of the EPA, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

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.

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.

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For SO 2 , 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.

The program includes 39 generation units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2, and Graham 2 plants).

The compliance obligations in the program started on January 1, 2019.

For NO X , the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas' SIP that determines that no electricity generation units are subject to BART for particulate matter.

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.

Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C.

Circuit Court, where we have intervened in support of the EPA.

We are in compliance with the rule, and the retirements of our Monticello, Big Brown, and Sandow 4 plants have enhanced our ability to comply.

The EPA is in the process of reconsidering the BART rule, and the challenges in the D.C.

Circuit Court have been held in abeyance pending the EPA's final action on reconsideration.

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 SO 2 limits on six facilities in Texas, including Martin Lake and Coleto Creek.

Under the current proposal, compliance would be required within 3 years for Martin Lake and 5 years for Coleto Creek.

Due to the announced shutdown for Coleto Creek, we do not anticipate any impacts at that facility, and we are evaluating potential compliance options at Martin Lake should this proposal become final.

We submitted comments to the EPA on this proposal in August 2023.

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)

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SO 2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants.

The final designations require Texas to develop nonattainment plans for these areas.

In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court.

In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable.

In May 2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring data supporting an attainment designation.

In June 2021, the EPA published two notices;

one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations.

We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, and this case was argued before the Fifth Circuit Court in July 2022.

In November 2016, the EPA finalized nonattainment designations for SO 2 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 SO 2 emissions from the plant.

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Emission reductions required are those necessary to demonstrate attainment with the NAAQS.

The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval.

In January 2024, in a split decision, the Fifth Circuit Court denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO 2 for the area around Martin Lake.

As a result of this decision, the EPA's nonattainment designation – originally made in 2016 – remains in place.

In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January 2024, which remains pending before the full Fifth Circuit Court.

In August 2024, the EPA proposed a Finding of Failure to attain the SO 2 standard for Rusk and Panola Counties, a partial approval and partial disapproval of the Texas SIP and a proposed federal plan for the area.

In December 2024, the EPA finalized the Finding of Failure to attain the standard and stated that it would take final action of the SIP partial approval and disapproval in a future action.

In February 2025, we, along with the State of Texas, filed a challenge to the Finding of Failure in the Fifth Circuit Court.

In February 2022, we and the TCEQ entered into an agreed order to reduce SO 2 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

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States will be required to develop SIPs to address emissions in areas with a higher (more stringent) classification.

Particulate Matte r

In February 2024, the EPA issued a rule addressing the annual health-based national ambient air quality standards for fine particulate matter (or PM2.5).

In general, the rule lowers the level of the annual PM2.5 standard from 12.0 micrograms per cubic meter (µg/m3) to 9.0 µg/m3.

The effective date of the rule is 60 days from publication in the Federal Register, and the earliest attainment date for areas exceeding the new standard is 2032.

Based on 2021-2023 design value associated with the rule, we have just four plants (Calumet (Illinois), Dicks Creek and Miami Fort (Ohio), and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard.

We have previously announced that our Miami Fort generation facility will close by the end of 2027.

States will have to develop a plan (by late 2027 at the earliest) to get those areas into attainment and there would be a possibility that additional controls would be required for those sites.

However, before the state begins this planning process, the designation process will occur within two years from the issuance of the final rule.

The states develop recommendations about the boundaries of the nonattainment counties and the EPA must finalize the designations including the boundaries of each nonattainment area.

Coal Combustion Residuals (CCR)/Groundwater

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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.

In addition, in January 2022, the EPA also made a series of public statements, including in a press release, that purported to impose new, more onerous closure requirements for CCR units.

In April 2022, we, along with the Utility Solid Waste Activities Group (USWAG), a trade association of over 130 utility operating companies, energy companies, and certain other industry associations, filed petitions for review with the D.C.

Circuit Court and asked the court to determine that the EPA cannot implement or enforce the new purported requirements because the EPA has not followed the required procedures.

The State of Texas and the TCEQ intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various environmental groups have intervened on behalf of the EPA.

In June 2024, the D.C.

Circuit Court dismissed the petitions filed challenging the EPA's January 2022 statements because it found the statements did not amend the existing CCR regulations, and thus the D.C.

Circuit Court did not have jurisdiction to review them.

Legacy CCR Rulemaking

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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 for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

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.

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We have completed closure activities at those ponds at our Baldwin facility.

At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C.

Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments ( i.e.

, the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014.

In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options.

In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General.

In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent order which the court subsequently entered.

Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter.

Per the terms of the agreed interim consent order, 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.

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.

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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 13 to the Financial Statements).

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.

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The rule does not mandate closure by removal at any site.

In May 2021, we, along with other industry petitioners, filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule.

In March 2024, the Illinois Fourth Judicial District issued a decision denying the industry petitions.

We do not anticipate any impacts from this decision.

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.

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.

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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 is reasonably possible for those to increase once the IEPA determines final closure requirements.

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.

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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.

The EPA published a final rule in October 2020 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 final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met.

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.

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The final rule also leaves in place the subcategory for facilities that permanently cease coal combustion by 2028.

We are reviewing the rule for impact but believe it will require additional treatment costs for legacy wastewaters during pond closure activities and combustion residual leachate.

At this time, we don't expect the impact of these additional treatment costs to be material.

A number of parties have since challenged the rule and that case is pending in the U.S.

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We are not a party to that litigation.

In February 2025, the Department of Justice on behalf of the EPA filed an 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 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

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Corporate Information

Vistra is a Delaware corporation whose common stock is listed and traded on the NYSE.

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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business