What changed in this filing

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Item 1. Business

2025-02-28 compared with 2024-02-29 · 218 added, 209 removed, 352 unchanged (55% of the section changed)

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Our generation fleet totals approximately 41,000 megawatts of generation capacity powered by a diverse portfolio, including natural gas, nuclear, coal, solar, and battery energy storage facilities.

Vistra is guided by four core principles:

we do business the right way, we work as a team, we compete to win, and we care about our stakeholders, including our customers, our communities where we work and live, our employees, and our investors.

Market Discussion

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

(i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure.

Our Texas, East, West and Sunset segments include our electricity generation operations, and our Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines.

The operations of Vistra, as an integrated retail electricity and power generation company, are further 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.

Retail Operations

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states and the District of Columbia.

Our TXU Energy brand, which has been used to sell electricity to customers in the competitive retail electricity market in Texas for approximately 20 years, is registered and protected by trademark law and is the only material intellectual property asset that we own.

We have also acquired the trade names for Ambit Energy, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S.

Gas & Electric through the Ambit Transaction, Crius Transaction and the Dynegy Merger, as the case may be.

As of December 31, 2023, we have reflected intangible assets on our balance sheet for our trade names of approximately $1.341 billion (see Note 6 to the Financial Statements).

The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 2.6 million customers.

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, which give our customers choice, convenience and control over how and when they use electricity and related services.

Our retail business also offers a comprehensive suite of green products and services, including 100% wind and solar options, as well as thermostats, dashboards and other programs designed to encourage reduced consumption and increased energy efficiency.

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 the largest competitive power generator in the U.S.

as measured by MWh.

as measured by MWh of generation capacity.

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

Net Capacity (MW)

% of Net Capacity

CCGT, CT or ST

Solar/Battery

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

Natural Gas CCGT, CT or ST 24,120 59%

Coal ST 8,428 21%

Nuclear 6,448 16%

Renewable Solar/Battery 1,474 4%

Fuel Oil CT 187 —%

Total 40,657 100%

Our natural gas-fueled generation fleet is comprised of 23 CCGT generation facilities totaling 19,742 MW and 10 peaking generation facilities totaling 4,378 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 reliable fuel supply.

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 8,428 MW of generation capacity.

Maintenance outages at these units are scheduled during the spring or fall off-peak demand periods.

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 the Oak Grove generation facility and coal purchased and transported by railcar at the Coleto Creek and Martin Lake generation facilities.

We own and operate two nuclear generation units at the Comanche Peak plant site in ERCOT, each of which is designed for a capacity of 1,200 MW.

Comanche Peak Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity.

Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods.

Every three years, the refueling cycle results in the refueling of both units during the same year, which occurred in 2023.

While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity.

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:

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.

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.

The Comanche Peak facility operated at a capacity factor of 90%, 94% and 96% in 2023, 2022 and 2021, respectively.

We have contracts in place for all of Comanche Peak's 2024 through 2027 nuclear fuel requirements.

We do not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion, enrichment and fabrication services in the foreseeable future, but we are closely monitoring developments that may arise out of the Russia and Ukraine conflict.

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

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 .

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

Net Capacity (MW)

% of Net Capacity

18,151 49% ERCOT

12,093 33% PJM, ISO-NE and NYISO

1,880 5% CAISO

4,578 13% MISO, PJM and ERCOT

Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) — Separate from our operations, ISOs/RTOs administer the transmission infrastructure and markets across a regional footprint in most of the markets in which we operate.

They are responsible for dispatching all generation facilities in their respective footprints and are responsible for both maximum utilization and reliable and efficient operation of the transmission system.

ISOs/RTOs administer energy and ancillary service markets in the short term, which usually consists of day-ahead and real-time markets.

Several ISOs/RTOs also ensure long-term planning reserves through monthly, semiannual, annual and multi-year capacity markets.

The ISOs/RTOs that oversee most of the wholesale power markets in which we operate currently impose, and will likely continue to impose, bid and price limits or other similar mechanisms.

Segment Net Capacity (MW) % of Net Capacity ISO/RTO

Texas 19,031 47% ERCOT

East 19,746 49% PJM, ISO-NE, MISO, and NYISO

West 1,880 4% CAISO

Total 40,657 100%

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 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.

In ISO/RTO regions with centrally dispatched market structures (e.g., ERCOT, PJM, ISO-NE, NYISO, MISO, and CAISO), all generators selling into the centralized market receive the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to balance supply with demand within a designated zone or at a given location.

Different zones or locations within the same ISO/RTO may produce different prices respective to other zones or locations within the same ISO/RTO due to transmission losses and congestion.

For example, a less efficient and/or less economical natural gas-fueled unit may be needed in some hours to meet demand.

If this unit's production is required to meet demand on the margin, its offer price will set the market clearing price for all dispatched generation in the same market (although the price paid at other zones or locations may vary because of transmission losses and congestion), regardless of the price that any other unit may have offered into the market.

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

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 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.

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

The PUCT has voted to recommend a Performance Credit Mechanism (PCM) that would align a required reliability standard with resource availability during higher-risk system conditions in a centrally-cleared market.

These changes are currently being evaluated by the PUCT and ERCOT and have not been implemented as of the date hereof.

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.

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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.

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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 in 2026.

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.

Beginning in July 2021, ERCOT has increased its ancillary service procurement volumes to maintain a more conservative level of operating reserves.

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.

The Texas legislature has also directed the creation of a new ancillary service, Dispatchable Reliability Reserve Service, that is currently projected to be implemented in 2026.

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.

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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 2025-2026 was delayed and is expected to be run in June 2024.

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.

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Energy prices vary among the locations in ISO-NE and are largely influenced by transmission constraints and fuel supply.

ISO-NE offers the Forward Capacity Market where capacity prices are determined through auctions.

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.

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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The balance is cleared through the seasonal and monthly capacity auctions.

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 and 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.

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.

MISO — MISO is an RTO that manages the flow of electricity from approximately 202,000 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.

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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 for the next planning year from June 1st of the current year to May 31st of the following year.

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.

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.

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.

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.

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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 also enters into electricity, natural gas and other commodity derivative contracts to reduce exposure to changes in prices primarily to mitigate the volatility of future revenues and fuel costs for our generation facilities and purchased power costs for our Retail segment.

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.

The demand for and market prices of electricity and natural gas are affected by weather.

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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 to efficiently utilize transportation from third-party pipelines and transmission from electric utilities to deliver electricity to end-users.

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.

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Business Strategy

Vistra is a leader in the clean power transition.

With a strong zero-carbon generation portfolio and a deliberate and responsible strategy to decarbonize, Vistra understands our obligation to balance reliability, affordability, and sustainability.

To align our strategy with this obligation we have defined four strategic priorities that we aim to execute against:

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

• Strategic energy transition that supports the reliability and affordability of electricity.

• Significant and consistent shareholder return of capital.

• Maintaining a strong balance sheet.

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

Our integrated business model distinguishes us from our electricity competitors as it pairs our reliable and efficient diversified generation fleet and wholesale commodity risk management capabilities with our retail platform.

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.

Stability and predictability of cash flows are essential as we evaluate economically attractive investments.

Strategic energy transition that supports the reliability and affordability of electricity.

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.

Significant and consistent shareholder return of capital.

We make thoughtful capital allocation decisions that balances the goal of returning significant and consistent capital to our stockholders through share repurchases and quarterly dividends with the allocation of capital to maintain current assets and explore opportunities for growth.

Maintaining a strong balance sheet.

Vistra' s disciplined approach to capital management supports our commitment to maintain a strong balance sheet.

A strong balance sheet ensures our access to diverse sources of liquidity and provides financial flexibility for our capital allocation decisions, including decisions to return significant and consistent capital to our stockholders.

Human Capital Resources

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

These values are:

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

with annual expected generation of over 200 TWh as of December 31, 2024.

Vistra is guided by four core principles:

• We do business the right way.

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

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 41,000 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.

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.

While the way we generate electricity may be changing, our essential role in providing reliable and affordable electricity is not.

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 believes our most valuable asset is our talented, dedicated and diverse group of employees who work together to achieve our objectives, and our top priority is ensuring their safety.

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, 2024, we had approximately 6,850 full-time employees, including approximately 1,940 employees under collective bargaining agreements.

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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 0.54, in the top quartile as compared to the Edison Electric Institute (EEI) 2022 Total Company Injury Data.

Although we do not focus on recordable incidents, our Total Recordable Incident rate (TRIR) for company employees was 0.72, in the top quartile as compared to the Edison Electric Institute (EEI) 2023 Total Company Injury Data for companies of comparable size.

We encourage near-miss reporting and review of events to promote a learning environment.

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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 Hopewell, Ontelaunee and Independence generation facilities completed reevaluations and were re-certified as VPP Star in 2023.

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

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.

Diversity, Equity and Inclusion

We recognize the value of having a diverse and inclusive workforce.

Our diversity includes all the ways we differ, such as age, gender, ethnicity and physical appearance, as well as underlying differences such as thoughts, styles, religions, nationality, education and numerous other traits.

Creating and maintaining an environment where differences are valued and respected enhances our ability to recruit and retain the best talent in the marketplace and to provide a work environment that allows all employees to be their best.

Vistra's diversity is evolving, and our Board and management are leading by example.

Currently, four of the eleven Board members are women, and two of the eleven are ethnically diverse.

Overall, 32% of the Company's workforce is ethnically diverse.

Women currently hold 24% of the Company's senior management positions, and ethnically diverse employees represent 27% of senior management.

During 2023, we continued our efforts to unlock the full potential of our people by launching multiple new initiatives within our diversity, equity, and inclusion efforts.

Our Chief Diversity Officer continued to develop and lead Vistra's employee-led Diversity, Equity and Inclusion Advisory Council, established in 2020.

We continued to utilize our fifteen Employee Resource Groups (ERGs) to promote the appreciation of and communicate awareness of diverse employee groups and communities and their contribution to the overall success of the organization, both internally and externally.

ERGs represent not only diverse cultures, but also employees with disabilities, the LGBTQ+ community and employees engaged in innovation and analytics.

The emphasis on skills-based hiring continues to evolve as we see increased mobility of employees throughout the organization as well as increased retention.

Vistra is elevating its commitment to disability diversity by increasing our commitment and support level with DisabilityIn.

We now have leaders on all eligible committees within the organization (executive sponsor, Chief Diversity Officer, ERG leader, accessibility).

We centralized our intern program to ensure a diverse intern pool from across the country and are expanding our college partnerships to ensure geographically diverse opportunities in research, sponsorships and recruitment.

Training on inclusion and acceptance is being presented to all frontline employees to ensure every employee is included in the conversation.

Vistra is active in our communities to promote inclusivity.

Vistra's supply chain diversity initiative seeks to reflect our customer base and workforce compositions through creating a diverse supply chain.

Vistra continued to expand its commitment to an inclusive economy by fostering mentorship of diverse businesses.

Further, in the fourth year of Vistra's $10 million five-year commitment to support underserved communities, Vistra provided funding to educational and economic development nonprofits around the country working to transform underserved communities for the better.

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.

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

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We have launched key programs to develop leaders at all levels of the organization.

Vistra's Essentials of Leadership provides new managers with skills to lead organizations in situational leadership, business acumen, inclusive leadership, and exposes them to best practices from across the company.

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 2023, Vistra refreshed our Front-Line Leader development program focusing on the development of supervisors and managers at our plants.

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.

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 450 employees participated in 2024.

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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The EPA has finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities.

Risk Factors for additional discussion of risks posed to us regarding regulatory requirements.

See Note 14 to the Financial Statements for a discussion of litigation related to EPA reviews.

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.

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.

Risk Factors and Note 15 to the Financial Statements for additional information.

Climate Change

There is continuing emphasis domestically and internationally on global climate change and how GHG emissions, such as CO 2 , contribute to global climate change.

There is continuing interest from our stakeholders domestically and internationally on global climate change and how GHG emissions, such as CO 2 , 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.

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We estimate that our generation facilities produced approximately 95 million short tons of CO 2 in the year ended 2024.

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.

To manage our environmental impact from our business activities and reduce our emissions profile, Vistra set emissions reduction targets.

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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.

In furtherance of Vistra's efforts to meet its net-zero target, Vistra expects to deploy multiple levers to transition the company to operating with net-zero emissions, including decarbonization of existing business lines and further diversification into low-to-no emission businesses, primarily renewables and battery ESS.

We have already taken or announced significant steps to transform our generation portfolio and reduce the emissions intensity of our generation fleet, including:

• Solar Projects — We operate solar generations facilities totaling 338 MW in Texas.

We have announced our plans to develop:

◦ additional solar generation facilities in Texas, with expected commercial operation dates beginning in 2025, and

◦ up to 300 MW of solar generation facilities at retired or to-be retired plant sites in Illinois with expected commercial operation dates ranging from 2024 to 2026.

• Battery Energy Storage Projects — We operate battery ESS totaling 270 MW in Texas and 750 MW in California.

We have announced our plans to develop up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois with expected commercial operation dates ranging from 2024 to 2026.

• Acquisition of CCGTs — In 2016 and 2017, we acquired 4,042 MW of CCGTs in Texas.

In 2018, we acquired 15,448 MW of CCGTs across various ISOs/RTOs in connection with the Dynegy Merger.

• Retirements of Fossil Fuel Generation — Since 2018, lignite/coal-fueled generation facilities retired include 4,167 MW in Texas, 4,040 MW in Illinois and 1,300 MW in Ohio.

We expect to retire an additional 4,578 MW of coal-fueled generation facilities in Illinois, Ohio and Texas no later than year-end 2027.

• Acquisition of Nuclear Generation Facilities — In 2023, we announced the acquisition of 4,048 MW of nuclear generation facilities in PJM from Energy Harbor.

We anticipate the transaction will close on March 1, 2024.

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.

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 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.

• Battery Energy Storage Projects — As of December 31, 2024, we owned battery ESS totaling 750 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.

• Solar Projects — As of December 31, 2024, we owned solar generations facilities totaling 338 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 will only invest in growth projects if we are confident in the expected returns.

See Note 3 to the Financial Statements for discussion of our solar and battery ESS projects and Note 4 to the Financial Statements for discussion of our retirement of generation facilities.

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.

See Note 15 to the Financial Statements for more information concerning the Series B Preferred Stock issued under our Green Finance Framework.

GHG Emissions

In July 2019, the EPA finalized a rule that repealed the Clean Power Plan (CPP) and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule.

The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generation units.

In response to challenges brought by environmental groups and certain states, the U.S.

Court of Appeals for the District of Columbia Circuit (D.C.

Circuit Court) vacated the ACE rule, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action.

In June 2022, the U.S.

Supreme Court issued an opinion reversing the D.C.

Circuit Court's decision, and finding that the EPA exceeded its authority under Section 111 of the Clean Air Act when the EPA set emission requirements in the CPP based on generation shifting.

In October 2022, the D.C.

Circuit Court issued an amended judgment, denying petitions for review of the ACE rule and challenges to the repeal of the CPP.

In addition, the EPA opened a docket seeking input on questions related to the regulation of GHGs under Section 111(d) which closed in March 2023.

In May 2023, the EPA released a new proposal regulating power plant GHG emissions, while also proposing to repeal the ACE rule.

The new GHG proposal sets limits for (a) new natural gas-fired combustion turbines, (b) existing coal-, oil- and natural gas-fired steam generation units, and (c) certain existing natural gas-fired combustion turbines.

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

Starting in 2030, the proposal would generally require more CO 2 emissions control at fossil fuel-fired power plants that operate more frequently and for more years and would phase in increasingly stringent CO 2 requirements over time.

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

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.

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.

Existing steam generation units must start complying with their standards of performance on January 1, 2030.

Existing combustion turbine units must start complying with their standards of performance on January 1, 2032, or January 1, 2035, depending on their subcategory.

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

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.

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.

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.

Circuit Court along with multiple motions to stay the rule.

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.

State Regulation of GHGs

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The spot market price of RGGI allowances required to operate these facilities as of December 31, 2024 was approximately $24.13 per allowance.

The spot market price of RGGI allowances required to operate our affected facilities during 2024 was approximately $16.21 per allowance on February 23, 2024.

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.

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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.

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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-NO X burners and/or overfire air systems on all units.

Cross-State Air Pollution Rule (CSAPR)

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).

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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.

The FIP applies to 22 states beginning with the 2023 ozone seasons.

States where Vistra operates electric 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 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.

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.

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.

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Circuit Court.

As a result of the stay, we do not believe the EPA has authority to implement the 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 FIP at least until the Fifth Circuit Court rules on the merits.

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 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 FIP as to Texas is stayed.

In July 2023, the Fifth Circuit Court ruled that the 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 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.

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 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.

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

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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.

The proposed agreed order associated with the SIP proposal reduces emission limits as of January 2022.

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.

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 EPA' 2016 nonattainment designation for SO 2 for the area around Martin Lake.

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.

We anticipate the EPA will likely move forward with either proposing a federal plan for the area in light of an approved consent decree between the Sierra Club and the EPA that requires the EPA taking final action promulgating a FIP for the nonattainment area by December 13, 2024 or the EPA may approve Texas' SIP submittal discussed above.

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

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.

Ozone Designations

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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.

The EPA is required to take action on areas that did not attain by that date by bumping up the region to a "moderate" designation with an attainment deadline of August 2024.

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.

Particulate Matte r

In February 2024, the EPA issued a 715-page rule addressing the annual health-based national ambient air quality standards for fine particulate matter (or PM2.5).

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.

At this time, we are still determining what impact, if any, this rule will have on our existing plants or any plants we may build in the future.

Based on 2020-2022 design value associated with the rule, we have just five plants (Oakland (California), Calumet (Illinois), Liberty (Pennsylvania), Miami Fort (Ohio) and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard.

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.

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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.

CCR/Groundwater

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.

Coal Combustion Residuals

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.

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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, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios.

In 2022 and 2023, we withdrew the applications for Coffeen, Martin Lake, Joppa and Zimmer stations because extensions were no longer needed.

In November 2020, environmental groups petitioned for review of this rule in the D.C.

Circuit Court, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020.

Also, in November 2020, the EPA finalized a rule that would allow an alternative liner demonstration for certain qualifying facilities.

In November 2020, we submitted an application for an alternate liner demonstration for one CCR unit at Martin Lake, however, we withdrew the application for an alternate liner demonstration in November 2023 after determining the pond was no longer needed for CCR.

In August 2021, we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following the announcement that Zimmer will close by May 31, 2022.

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.

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.

The EPA issued these new purported requirements without prior notice and without following the legal requirements for adopting new rules.

These new purported requirements announced by the EPA are contrary to existing regulations and the EPA's prior positions.

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

Briefing before the D.C.

Circuit Court is complete, and the court will hear argument in March 2024.

In May 2023, the EPA issued another proposal that further revises the federal CCR rule that would expand coverage of groundwater monitoring and closure requirements to the following two new categories of units:

(a) legacy units which are CCR impoundments at inactive sites that ceased receiving waste before October 19, 2015 and (b) so-called "CCR management units" which generally could encompass areas of CCR located at a facility that is currently regulated by the existing CCR rule.

CCR Management Units, as defined by the EPA in the proposal, could include any ash deposits, haul roads, and previously closed impoundments and landfills.

As part of the proposed rule, the EPA identified 134 CCR management units at 82 different facilities across the country, including six 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 this proposal, if finalized, will have any impact on that site.

We are continuing to evaluate what would be required of the CCR management units identified in the proposal should the proposal become final in its current form.

We submitted comments in July 2023.

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

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

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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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 May 2018, Prairie Rivers Network (PRN) filed a citizen suit in federal court in Illinois against Dynegy Midwest Generation, LLC (DMG), alleging violations of the Clean Water Act for alleged unauthorized discharges.

In August 2018, we filed a motion to dismiss the lawsuit.

In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor.

In June 2021, the U.S.

Court of Appeals for the Seventh Circuit affirmed the district court's dismissal of the lawsuit.

In April 2019, PRN also filed a complaint against DMG before the Illinois Pollution Control Board (IPCB), alleging that groundwater flows allegedly associated with the ash impoundments at the Vermilion site have resulted in exceedances both of surface water standards and Illinois groundwater standards dating back to 1992.

We answered that complaint in July 2021.

In July 2023, PRN filed an unopposed motion to voluntarily dismiss the case with prejudice, which the IPCB granted in August 2023 and closed the case.

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 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.

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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 newly implemented Illinois Coal Ash regulation (discussed below) and close the site by removal.

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.

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 our consolidated balance sheets (see Note 22 to the Financial Statements).

These proposed closure costs are reflected in the ARO in the consolidated balance sheets (see Note 13 to the Financial Statements).

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.

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

In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule and that case remains pending.

Other parties have also filed appeals of certain provisions of the final rule.

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.

For all of the above 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.

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.

However, 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 believe are appropriate based on existing closure requirements and protective of the environment for each location.

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.

Once the IEPA acts on our permit applications, we will reassess the decommissioning costs and adjust our ARO liabilities accordingly.

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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 March 2023, the EPA published its proposed supplemental ELG rule, which retains the retirement exemption from the 2020 ELG rule and sets new limits for plants that are continuing to operate.

The proposed rule also establishes pretreatment standards for combustion residual leachate, and we are currently evaluating the impact of those proposed requirements.

We submitted comments on the proposal in May 2023.

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.

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.

Court of Appeals for the Eighth Circuit.

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.

Radioactive Waste

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Corporate Information

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

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

Our principal executive office is located at 6555 Sierra Drive, Irving, Texas 75039.

8 unchanged sentences

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