Vistra Corp

Proposed Merger with Energy Harbor

On March 6, 2023, Vistra Operations and its wholly-owned subsidiary (Merger Sub) entered into a Transaction Agreement with Energy Harbor pursuant to which, upon the terms and subject to the conditions thereof, Merger Sub will be merged with and into Energy Harbor, with Energy Harbor surviving as an indirect subsidiary of Vistra. The Transaction Agreement, the Merger and the other Transactions were approved by each of Vistra's Board and Energy Harbor's board of directors. On February 16, 2024, we received approval from FERC to acquire Energy Harbor. FERC's approval was the last regulatory approval needed, and we anticipate closing on March 1, 2024. See Note 2 to the Financial Statements for more information concerning the Transaction Agreement.

Inflation Reduction Act of 2022

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including a nuclear PTC, a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. Treasury regulations are expected to further define the scope of the legislation in many important respects over the next twelve months. The excise tax on stock repurchases is not expected to have a material impact on our financial statements. Vistra is not subject to the CAMT in the 2023 tax year since it only applies to corporations that have 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 for periods after the law takes effect. See Note 1 for our accounting policy related to refundable and transferable PTCs and ITCs.

Repurchase of TRA Rights and Preferred Stock Issuance

On December 29, 2023, Vistra repurchased (Repurchase) approximately 74% of the outstanding beneficial interests in the TRA Rights to receive payments under the TRA from a select group of registered holders of the TRA Rights (Selling Holders) in exchange for consideration of $1.50 per repurchased TRA Right, totaling an aggregate purchase price for the Repurchase of approximately $476 million. The shares of Series C Preferred Stock were issued (see Note 15 to the Financial Statements) to the Selling Holders in exchange for the TRA Rights in a transaction exempt from registration pursuant to Section 4(a)(2) of the Securities Act. As part of the transaction, on January 29, 2024, the Company filed a shelf registration statement on Form S-3 registering the resale of the shares by the Selling Holders of Series C Preferred Stock from time to time under Rule 415 of the Securities Act. If the Company repurchases TRA Rights at any time during the 180 days following December 29, 2023 at a price per TRA Right greater than $1.50, the Company will pay the Selling Holders an amount equal to such excess purchase price per TRA Right sold by the Selling Holders.

On January 11, 2024, Vistra repurchased an additional 43,494,944 TRA Rights from a select group of registered holders of TRA Rights in exchange for consideration of $1.50 per repurchased TRA Right. Total consideration of $65 million was paid using cash on hand.

On January 31, 2024, Vistra announced a cash tender offer to purchase any and all outstanding TRA Rights in exchange for consideration of $1.50 per tendered TRA Right accepted for purchase prior to close of business on February 13, 2024 (Early Tender Date), which included an early tender premium of $0.05 per TRA Right accepted for purchase. As of the Early Tender Date, 55,056,931 TRA Rights were accepted for purchase for total consideration of $83 million, which was paid using cash on hand. TRA Rights accepted for purchase after the Early Tender Date, but prior to the close of business on February 28, 2024, will receive consideration of $1.45 per TRA Right accepted for purchase, which will be paid in March 2024 using cash on hand.

As of the Early Tender Date, we have repurchased an aggregate 98% of the original outstanding TRA Rights, of which 10,430,083 TRA Rights remain outstanding.

See Note 8 to the Financial Statements for details of the TRA and Note 15 to the Financial Statements for details of the Series C Preferred Stock.

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 and capitalization of market opportunities which drove strong earnings during the year ended December 31, 2023, highlighting 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 for 2023 and beyond 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 through products and solutions that differentiate from our competitors leading to an increase in residential customer counts within markets we continue to operate.

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

•In June 2023, an additional 350 MW battery ESS at our Moss Landing Power Plant site commenced commercial operations.

•As of June 30, 2023, the net proceeds of our Series B Preferred Stock were fully allocated to eligible solar and battery projects, pursuant to our Green Finance Framework.

•We continued development and construction activities on the planned development of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois.

•We retired our Edwards coal generation plant on January 1, 2023.

Significant and consistent shareholder return of capital.

•During the year ended December 31, 2023, we paid dividends to common stockholders totaling $313 million.

•During the year ended December 31, 2023, we repurchased 45 million shares for $1.3 billion under our stock repurchase program. Total shares repurchased under the program established in October 2021 are 143 million shares for $3.5 billion. See Note 15 to the Financial Statements for more information about our dividend and Share Repurchase Program.

Maintaining a strong balance sheet.

•In December 2023, we issued $400 million of 6.950% Senior Secured Notes due 2033 and $350 million of 7.750% Senior Unsecured Notes due 2031 in which the net proceeds were used to fund the tender offer (Senior Secured Notes Tender Offer) to purchase for cash $759 million aggregate principal amount of certain notes in January 2024, including $58 million of 4.875% Senior Secured Notes due 2024, $345 million of 3.550% Senior Secured Notes due 2024 and $356 million of the 5.125% Senior Secured Notes due 2025.

During the year ended December 31, 2023, 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, summer scarcity pricing events in Texas and effectiveness of our comprehensive hedging strategy and the value we were able to lock in as forward power and natural gas curves increased beginning in 2022.

Macroeconomic Conditions

With forward power and natural gas curves increasing during 2022 and the continued volatility in 2023, we have increased our hedging for future periods. As of December 31, 2023, we have hedged approximately 91% of our expected generation volumes on average for the two-year period 2024 through 2025 (with approximately 98% hedged for 2024 and approximately 83% hedged for 2025).

The industry continues to experience supply chain constraints that have reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased the lead time to procure certain materials necessary to maintain 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. 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 expected refinancing or borrowing costs, including project financing for our development projects and refinancing expected in connection with debt due in 2024 and beyond.

We are closely monitoring 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. In addition, current policies being considered by the U.S. Congress, namely H.R. 1042 the Prohibiting Russian Uranium Imports Act, would restrict imports of uranium if signed into law. The bill passed out of the House of Representatives in December 2023, and the future of the bill remains uncertain as it awaits consideration in the Senate. Our 2024 refueling has not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel. We are taking 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 facility through potential Russian supply disruption. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance, and therefore, we expect to have enough nuclear fuel to support all our refueling needs, including the Energy Harbor facilities following the expected closing of the Transactions, through 2027. If imports from Russia are restricted, refueling operations of U.S. merchant nuclear power generators could be challenged in future years.

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, West and Sunset 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 2024-2025, 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 2025-2026, 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 2026-2027 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 2024 through 2027 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.