Vistra Corp

Merger with Energy Harbor

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

Acquisition of Noncontrolling Interest

On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (as amended, the UPAs) with each of Nuveen and Avenue, pursuant to which Vistra Vision Holdings agreed to purchase each of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision for approximately $3.2 billion in cash (collectively, the Transaction). The Transaction closed on December 31, 2024 (the Closing Date) and Vistra Vision Holdings now owns 100% of the equity interests in Vistra Vision. See Note 9 to the Financial Statements.

Nuclear Plant License Renewals

In July 2024, our application for license renewal at our two-unit Comanche Peak Nuclear Plant was approved by the NRC. The licenses for Units 1 and 2 now extend into 2050 and 2053, respectively, an additional 20 years beyond our original licenses.

In 2023, the Perry Nuclear Plant filed a license extension application to operate through 2046, an additional 20 years beyond the existing license. A decision from the NRC is expected in late 2025.

Planned Gas-Fueled Dispatchable Power in ERCOT

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

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

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

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

Our announced plan is based on market reforms that policymakers passed in the 2023 Texas legislative session, which ERCOT and the PUCT are currently implementing. These market reforms are focused on grid reliability and proper market signals. If successfully implemented, they could offer the regulatory framework necessary for Vistra to confidently make the long-term investments in these capacity projects. In addition, in July 2024, we filed applications with the PUCT under the Texas Energy Fund loan program seeking financing for the 860 MW of new advanced simple-cycle peaking plants referenced above. In August 2024, the PUCT notified Vistra that an application for one of its west Texas advanced simple-cycle peaking plants was selected for due diligence as part of the Texas Energy Fund loan program, which is ongoing. Vistra's other application for a second west Texas gas plant remains active. An invitation to due diligence does not mean an applicant is awarded a loan. Vistra's decision to move forward with the new west Texas gas plant project is contingent upon supportive market reforms, approval of our Texas Energy Fund loan application, and other factors, including state and federal environmental regulations and long-term wholesale trends that continue to support gas generation.

Moss Landing 300 Battery and Martin Lake Unit 1 Updates

In January 2025, a fire occurred at our Moss Landing 300 MW battery energy storage facility in CAISO. We are still investigating the cause and impacts, but expect to write off approximately $400 million of plant value to depreciation expense in the first quarter of 2025, representing the facility's remaining net book value. Moss Landing 300 is part of the Moss Landing complex, which includes two other battery facilities and a gas plant, with an aggregate book value of approximately $1 billion including Moss Landing 300. While the gas plant is operational, the other two battery facilities remain offline as we investigate the fire. Additional costs incurred from the events include loss of revenue from the facilities being offline, and may include litigation costs and penalties under contracts. We will continue to assess if a triggering event has occurred to evaluate impairment for the other complex assets.

On November 27, 2024, we experienced a fire at Unit 1 of our Martin Lake facility in ERCOT, an 815 MW unit. The depreciation expense associated with the damaged property was less than $1 million. We currently expect the unit to return to service in June 2025.

We expect to recover a significant portion of the direct losses incurred from each event through property damage insurance and business interruption insurance. However, given uncertainty in timing of recoveries and potential indirect impacts to other facilities, we cannot predict the net impact these events will have on our results of operations for 2025.

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC, and a first-time stand-alone battery storage investment tax credit. The IRA also implements a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. The section 45U nuclear PTC is available to existing nuclear facilities from 2024 through 2032 and provides a federal tax credit of up to $15 per MWh, subject to phase out as power prices increase above $25 per MWh (each subject to annual inflation adjustments). The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance. As discussed in Note 4, we recognized transferable nuclear PTC revenues of $545 million in the year ended December 31, 2024. Treasury regulations are expected to further define the scope of the legislation in many important respects, including critical guidance interpreting the nuclear PTC. This guidance could have a material impact on our estimate and would be reflected as a change in estimate in the period in which the guidance is received. We do not expect Vistra to be subject to the CAMT in the 2024 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes.

Financial and Operating Performance

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

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

•We continued to execute our integrated business model through exceptional operational performance by capitalizing on market opportunities that drove strong earnings for the year ended December 31, 2024. This highlights our competitive advantage of coupling retail with our reliable and efficient generation fleet and wholesale commodity risk management capabilities, which reduces the effects of commodity price movements and contributes to the stability and predictability of our cash flows.

•Our commercial team focused on effectively and efficiently managing risk by opportunistically hedging and optimizing our assets and business positions, which led to strong plant operating performance and energy margins.

•Our retail brands served the retail electricity and natural gas needs of end-use residential, small business, and commercial and industrial electricity customers through multiple sales and marketing channels with products and solutions that differentiates Vistra from our competitors.

Disciplined capital allocation.

•During the year ended December 31, 2024, we paid dividends to common stockholders totaling $305 million.

•In February 2024 and October 2024, the Board authorized incremental amounts of $1.5 billion and $1.0 billion, respectively, under our stock repurchase program established in October 2021. During the year ended December 31, 2024, we repurchased 16.6 million shares for $1.2 billion under the program. Through February 24, 2025, total shares repurchased under the program totaled 160 million shares for $4.9 billion, and we have $1.9 billion available for additional repurchases under the program (see Note 16 to the Financial Statements).

Maintaining a resilient balance sheet.

•We further diversified our sources of liquidity and improved associated borrowing costs and credit terms through a number of enhancements and amendments to our facilities throughout the year, including (i) the expansion and extension of both our Revolving Credit Facility (expanded by $265 million and extended to 2029) and our Commodity-Linked Facility (expanded facility limit by $175 million and extended to October 2025), (ii) amending both the Vistra Operations Term Loan B-3 Facility and the Vistra Zero Term Loan B Facility to reduce the fixed spread interest by 25 and 75 basis points, respectively, (iii) establishing a $500 million alternative letter of credit facility, and (iv) expanding and extending the Receivables Facility (expanded the purchase limit by $250 million and extended to July 2025).

•In April 2024, we issued $500 million of 6.000% senior secured notes due 2034 and $1.0 billion of 6.875% senior unsecured notes due 2032. The net proceeds from these issuances were used to refinance senior secured debt maturities in May 2024 and July 2024 and for general corporate purposes.

•In December 2024, we issued $500 million of 5.050% senior secured notes due 2026 and $750 million of 5.700% senior secured notes due 2034. The net proceeds from these issuances were or will be used for general corporate purposes, including to refinance senior secured debt maturities in May 2025 and payments associated with the Transaction for the purchase of the remaining interest in Vistra Vision.

•In December 2024, we entered into the BCOP Credit Agreement to fund the development of solar generation and battery ESS facilities in Illinois and Texas.

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

•In March 2024, we completed the acquisition of Energy Harbor, adding an additional 4,048 MW of nuclear generation to our fleet.

•We reached commercial operations for two solar facilities totaling 112 MW of capacity at retired plant sites in Illinois and continued development and construction activities on additional facilities in Texas and at retired or to-be-retired plant sites in Illinois.

•We announced plans to repower the Coleto Creek coal generation facility as a natural gas-fueled facility upon its retirement no later than 2027.

During the year ended December 31, 2024, our operating segments delivered strong operating performance with a disciplined focus on cost management, while generating and selling essential electricity in a safe and reliable manner. Our performance reflected strong plant operating performance, growth of our retail business and the effectiveness of our comprehensive hedging strategy.

Macroeconomic Conditions

Historically, the base case assumption for U.S. electricity demand was for modest growth driven by the interplay of growth in population, industrial activity (such as an on-shore manufacturing) and new demand sources (such as electric vehicles), partially offset by continued advancements in energy efficiency. Multiple demand drivers such as emergence of large load data centers and electrification of oil field operations (specifically in the Permian Basin of west Texas), are expected to continue to accelerate load growth in the geographic regions we serve. We are in various discussions with interested counterparties for the potential sale of power from our nuclear and gas facilities pursuant to long-term agreements to supply large load facilities. Such potential transactions are subject to certain risks and uncertainties, including potential regulatory review and/or approval and adverse legislative action, which could impact the timing of, and our ability to consummate, any potential transaction.

The industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment and supply relevant to construction of new generation facilities, and increased (i) the lead time to procure certain materials necessary to maintain, and (ii) the labor costs associated with maintenance activity on our natural gas, nuclear and coal fleet. We are proactively managing the increased costs of materials and supply chain disruptions and continuing to prudently re-evaluate the business cases and timing of our planned development projects, which has resulted in a deferral of some of our planned capital spend for our renewables projects and could impact the feasibility of additional projects. In addition, we have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages, and our Vistra Zero operational and development projects are anticipated to benefit from the impact of the IRA. The inflationary environment continues to drive elevated interest rates, resulting in increased refinancing or borrowing costs, including future non-recourse financing for our development projects and future refinancing expected in connection with future debt maturities.

We continue to closely monitor developments in the Russia and Ukraine conflict, specifically with regards to, (i) sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and (ii) actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. The Prohibiting Russian Uranium Imports Act (PRUI Act) was approved by Congress, signed into law by President Biden, and took effect on August 11, 2024. The PRUI Act prohibits importation of Russian uranium; however, the Department of Energy can issue waivers (subject to decreasing annual caps) until December 31, 2027 if there is no alternate source of low-enriched uranium available to keep U.S. nuclear reactors operating or is in the national interest. Additionally, passage of the PRUI Act enabled the allocation of $2.72 billion in federal funding to ramp up production of domestic uranium fuel. On November 15, 2024, the Russian Federation temporarily suspended shipments of uranium to the U.S., stating that they would grant future export licenses on a case-by-case basis. Our 2024 and 2025 refueling plans have not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel impacting our refueling schedules. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance. We have nuclear fuel contracted to support all our refueling needs through 2029. 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.

Capacity Markets

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

PJM

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

Our capacity sales in PJM, net of purchases, aggregated by planning year and capacity type through planning year 2025-2026, are as follows:

NYISO

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

Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through bilateral trades. Our capacity sales, aggregated by season through winter 2026-2027, are as follows:

ISO-NE

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

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

MISO

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

MISO capacity sales through planning year 2027-2028 are as follows:

CAISO

Our capacity sales as part of the California Public Utilities Commission Resource Adequacy (RA) Program in California, aggregated by calendar year for 2025 through 2028 for Moss Landing, are as follows:

Electricity Prices

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

Wholesale electricity prices generally track to increases or decreases in the price of natural gas, with exceptions such as when ERCOT power prices rise significantly during weather events as a result of the scarcity of available generation resources relative to power demand. The price of natural gas is volatile; therefore, the costs to operate a natural gas-fueled generation facility can be volatile as well. In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating power at our nuclear-, lignite- and coal-fueled facilities; however, all other factors being equal, changes in natural gas prices affect our operating margins on these facilities as electricity prices generally track to natural gas prices. Other variables that could impact electricity prices include, but are not limited to, the price of other fuels, generation resources in the region, weather, on-going competition, emerging technologies, and macroeconomic and regulatory factors.

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

As a result of our exposure to the variability of natural gas prices and Market Heat Rates, retail sales and hedging activities are critical to our operating results and maintaining consistent cash flow levels. Our integrated power generation and retail electricity business provides us opportunities to hedge our generation position utilizing retail electricity markets as a sales channel. Our approach to managing electricity price risk focuses on the following:

•employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related contracts intended to partially hedge gross margins;

•continuing focus on cost management to better withstand gross margin volatility;

•following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the magnitude and costs of commodity price, liquidity risk and retail demand variability; and

•improving retail customer service to attract and retain high-value customers.