NYSE: VST

Retail Operations

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

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

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

Electricity Generation Operations

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

Primary FuelTechnologyNet Capacity (MW)% of Net Capacity

Natural GasCCGT, CT or ST26,989 62%

CoalST8,743 20%

UraniumNuclear6,448 15%

RenewableSolar/Battery1,274 3%

Fuel OilCT187 —%

Total43,641 100%

1

VISTRA CORP.

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

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

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

UnitISONet Capacity (MW)Refueling Outage FrequencyLicense Expiration Date

Comanche Peak Unit 1ERCOT1,200 18 Months2050

Comanche Peak Unit 2ERCOT1,200 18 Months2053

Beaver Valley Unit 1PJM939 18 Months2036

Beaver Valley Unit 2PJM933 18 Months2047

PerryPJM1,268 24 Months
2046

Davis-BessePJM908 24 Months2037

Total6,448

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

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

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

SegmentNet Capacity (MW)% of Net CapacityISO/RTO

Texas19,858 46%ERCOT

East22,254 51%PJM, ISO-NE, MISO, and NYISO

West1,529 3%CAISO

Total43,641 100%

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

2

VISTRA CORP.

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

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

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

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

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

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

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

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

3

VISTRA CORP.

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

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

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

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

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

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

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

4

VISTRA CORP.

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

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

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

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

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

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

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

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

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

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

5

VISTRA CORP.

Competition

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