Vistra Corp. 10-K

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, AND RESULTS OF OPERATIONS The following discussion and analysis of our financial condition and results of operations should be read together with the consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data . See Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations in our 202 3 Form 10-K for a discussion of our financial condition and results of operations for the year ended December 31, 2022 and for the year ended December 31, 2023 compared to the year ended December 31, 2022, which is incorporated here by reference. The Sunset segment was eliminated in the fourth quarter of 2024, resulting in the recast of results for four coal facilities to the East segment and one coal facility to the Texas segment (see Note 19 to the Financial Statements). The recast is reflected in the results of operations for the years ended December 31, 2024 and 2023. The re-segmentation did not result in a material change in the reported results for the East and Texas segments for the year ended December 31, 2023 compared to the year ended December 31, 2022. 50 Table of Contents Significant Activities and Events, and Items Influencing Future Performance 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. 51 Table of Contents 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. 52 Table of Contents • 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. 53 Table of Contents 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: 2024-2025 2025-2026 (average price per MW-day) RTO zone $ 28.92 $ 269.92 ComEd zone 28.92 269.92 MAAC zone 49.49 269.92 EMAAC zone 53.60 269.92 ATSI zone 28.92 269.92 DEOK zone 96.24 269.92 DOM zone 28.92 444.26 54 Table of Contents Our capacity sales in PJM, net of purchases, aggregated by planning year and capacity type through planning year 2025-2026, are as follows: East Segment 2024-2025 2025-2026 CP auction capacity sold, net (MW) 9,935 10,255 Bilateral capacity sold, net (MW) 2,127 330 Total segment capacity sold, net (MW) 12,062 10,585 Average price per MW-day $ 41.38 $ 267.12 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: Winter 2024 - 2025 Price per kW-month $ 2.00 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: East Segment Winter 2024 - 2025 Summer 2025 Winter 2025 - 2026 Summer 2026 Winter 2026 - 2027 Auction capacity sold (MW) 77 — — — — Bilateral capacity sold (MW) 943 550 268 — — Total capacity sold (MW) 1,020 550 268 — — Average price per kW-month $ 3.09 $ 4.51 $ 4.10 $ — $ — 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: 2024-2025 2025-2026 2026-2027 2027-2028 Price per kW-month $ 2.61 $ 2.59 $ 2.59 $ 3.58 We continue to market and pursue longer term multi-year capacity transactions that extend through planning year 2027-2028. East Segment 2024-2025 2025-2026 2026-2027 2027-2028 Auction capacity sold (MW) 3,221 3,032 2,960 3,261 Bilateral capacity sold (MW) 78 78 58 8 Total capacity sold (MW) 3,299 3,110 3,018 3,269 Average price per kW-month $ 3.10 $ 2.72 $ 2.60 $ 3.58 MISO The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year: 2024-2025 Price per MW-day $ 20.08 55 Table of Contents MISO capacity sales through planning year 2027-2028 are as follows: East Segment 2024-2025 2025-2026 2026-2027 2027-2028 Auction capacity sold (MW) 1,095 — — — Bilateral capacity sold (MW) 682 891 515 24 Total MISO segment capacity sold (MW) 1,777 891 515 24 Average price per kW-month $ 3.02 $ 4.52 $ 4.44 $ 4.96 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: West Segment 2025 2026 2027 2028 Bilateral capacity sold (Avg MW) 1,816 1,575 1,275 750 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. 56 Table of Contents Critical Accounting Estimates See Note 1 of the consolidated financial statements for a description of our accounting policies. The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in our application of GAAP. Business Combinations Determining fair values of assets acquired and liabilities assumed in the Energy Harbor Merger requires significant estimates and judgments. We determined fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 2 to the Financial Statements. The determination of the fair value of property, plant, and equipment contributed and acquired, as well as nuclear decommissioning asset retirement obligations required the most significant level of estimation uncertainty. The fair value of each power plant acquired in the Energy Harbor Merger and the fair value of the contributed nuclear business was estimated using a combination of the income approach and the market approach. The income approach was based on the discounted cash flow method, incorporating (i) our estimates of forecasted future growth and long-term prices of electricity, capacity, and nuclear fuel, and (ii) financial performance including revenues, gross margins, operating expenses, taxes, working capital, and capital asset requirements. Projected cash flows were then discounted to a present value employing a discount rate that accounts for the estimated market weighted-average cost of capital, along with any risks unique to the subject cash flows. These estimates are subjective in nature and require judgment to interpret market data. The market valuation method utilized prices paid for reasonably similar assets by other purchasers in the relevant market, with adjustments relating to physical differences in the asset as well as their locations. See Asset Retirement Obligations (ARO) critical accounting estimate for methodology and assumptions used to estimate the nuclear decommissioning ARO acquired in the Energy Harbor Merger. Derivative Instruments and Mark-to-Market Accounting We enter into contracts for the purchase and sale of energy-related commodities, as well as other derivative instruments such as options, swaps, futures, and forwards, primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques. Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. Where quoted market prices are not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative instruments valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity (including certain retail contracts), natural gas and coal, (ii) electricity, natural gas and coal options, and (iii) financial transmission rights. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using proprietary modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. Any significant changes to these inputs could result in a material change to the value of the assets or liabilities recorded in the consolidated balance sheets and could result in a material change to the unrealized gains or losses recorded in the consolidated statements of operations. Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections, which generally eliminate the requirement for mark-to-market recognition in net income. Normal purchases and sales (NPNS) are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are accounted for on an accrual basis. Determining whether a contract qualifies for the normal purchase or sale election requires judgment as to whether or not the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements. If it is determined that a transaction designated as a normal purchase or sale no longer meets the scope exception, the related contract would be recorded on the balance sheet at fair value with immediate recognition through earnings. See Notes 11 and 12 to the Financial Statements for additional information. 57 Table of Contents Accounting for Income Taxes Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgments of the timing and probability of recognition of income and deductions by taxing authorities. Further, we assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we would record a valuation allowance against such deferred tax assets for the amount we would not expect to utilize, which would reduce the carrying value of the deferred tax amounts. When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following: • the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax assets; • the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward; and • the amounts and history of income or losses, adjusted for certain non-recurring items. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. Income tax returns are regularly subject to examination by applicable tax authorities. In management's opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination. See Notes 1 and 5 to the Financial Statements for additional information. Asset Retirement Obligations (ARO) An ARO liability is initially recorded at fair value when it is initially incurred and the amount of the liability can be reasonably estimated. In estimating the ARO liability, we are required to make significant estimates and assumptions. Our ARO liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, and remediation or closure of coal ash basins. On the Merger Date, we recognized ARO liabilities for the Beaver Valley, Perry and Davis-Besse nuclear plants acquired from Energy Harbor. For the estimates and assumptions of the nuclear generation plant decommissioning, we use unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs and estimates of the timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. We consider the following decommissioning scenarios: (i) DECON, which assumes major decommissioning activities begin shortly after the facility ceases operations, and (ii) SAFSTOR, which assumes the nuclear facility is placed and maintained in a condition during decommissioning that allows the nuclear facility to be safely stored until subsequently decontaminated within 60 years after the facility ceases operations. Decommissioning cost studies are updated for each of our nuclear units at least every five years unless circumstances warrant a more frequent update. In estimating the liability assumed in the Energy Harbor Merger, we have included an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate the Perry Nuclear Plant through 2046. The estimates and assumptions required for the lignite mining land reclamation include, estimates such as costs to fill in mining pits and interpretation of the mining permit closure requirements. We estimate the costs to fill in mining pits utilizing a proprietary model to determine the volume of the pit. Our AROs are adjusted on a regular basis to reflect the passage of time and to incorporate revisions to estimates and judgments including, planned plant retirement dates, amounts and timing of future cash expenditures, discount rates, cost escalation factors, market risk premiums, inflation rates, and if applicable, experience with government regulators regarding similar obligations. See Note 13 to the Financial Statements for additional information. 58 Table of Contents Impairment of Goodwill and Other Long-Lived Assets Goodwill and Intangible Assets with Indefinite Useful Lives Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the our retail trade names are not amortized and are subject to impairment testing annually, or when events or changes in the business environment indicate that the carrying value of the reporting unit may exceed its fair value. Evaluating goodwill and intangible assets with indefinite useful lives involves applying significant assumptions including discount rates, forecasted results for the applicable reporting unit and retail trade name, market multiples, and growth rates. These assumptions are forward looking and could be affected by future economic and market conditions. Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill and retail trade name intangible asset is more likely than not less than the fair value. If the entity determines the carrying value is not more likely greater than the fair value, no further testing for impairment is required. On the most recent testing date, we performed a qualitative assessment and determined that it was more likely than not that the fair value of our reporting units and retail trade names exceeded their carrying value. Significant qualitative factors were evaluated included reporting unit and trade name financial performance, market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, and interest rates. See Note 7 to the Financial Statements for additional information. Long-Lived Assets We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Indicators of impairment for our generation facilities include an expectation of continuing long-term declines in natural gas prices and/or Market Heat Rates, an expectation that "more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life, or additional environmental regulations significantly decrease the cash flows expected from the associated assets. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows given the diverse fuel mix and output rates of our generation asset groups. See Note 20 to the Financial Statements for additional information. After identifying an indicator of impairment, recoverability of long-lived assets is determined by a comparison of the carrying amount of the long-lived asset group to the net cash flows expected to be generated by the asset group. Assumptions used in our estimate of net cash flows of the asset group include, forward natural gas and electricity prices, forward capacity prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices, and forecasted operating costs. The carrying value of such asset groups is determined to be unrecoverable if the projected undiscounted cash flows are less than the carrying value. If an asset group carrying value is determined to be unrecoverable, fair value will be calculated based on a market participant view and a loss will be recorded for the amount the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows (income approach) and supported by available market valuations, if applicable. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward electricity prices, forward capacity prices, Market Heat Rates, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices, and the discount rate applied to the forecasted cash flows. Any significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived assets. Nuclear PTC Revenues Nuclear PTC revenues are accounted for by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance. Nuclear PTC revenues are based on annual gross receipts generated from qualifying nuclear production in the calendar year. Treasury regulations are expected to further provide interpretive guidance on the definition of gross receipts over the next year. Given the lack of guidance to date, we recognized 2024 nuclear PTC revenues based on our best estimate and interpretation of gross receipts which includes settled spot energy revenues and capacity revenues at each nuclear unit, and excludes any hedges. Any interpretive guidance on the definition of gross receipts which differs from the interpretation used in our estimate could result in a material change to PTC revenues attributable to 2024 and would be reflected as a change in estimate in the period in which the guidance is received. 59 Table of Contents We have determined that we will meet the prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier, which is reflected in the amount of nuclear PTC revenue recognized in 2024. Results of Operations Net income increased $1.32 billion to Net income of $2.812 billion for the year ended December 31, 2024 compared to the year ended December 31, 2023. For additional information see the following discussion of our results of operations. EBITDA and Adjusted EBITDA In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed (i) with our GAAP results and (ii) the accompanying reconciliations to corresponding GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition, an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review the consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure. When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss). Vistra Consolidated Financial Results — Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the year ended December 31, 2024: Year Ended December 31, 2024 Retail Texas East West Asset Closure Eliminations / Corporate and Other Vistra Consolidated (in millions) Operating revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ (7,506) $ 17,224 Fuel, purchased power costs, and delivery fees (10,276) (1,596) (2,698) (221) (3) 7,509 (7,285) Operating costs (159) (996) (1,103) (72) (81) (3) (2,414) Depreciation and amortization (114) (581) (996) (86) — (66) (1,843) Selling, general, and administrative expenses (977) (169) (148) (25) (43) (239) (1,601) Operating income (loss) 1,271 2,052 716 473 (126) (305) 4,081 Other income 1 39 181 3 16 72 312 Other deductions (2) (4) (4) (6) (2) (3) (21) Interest expense and related charges (54) 46 9 1 (4) (898) (900) Impacts of Tax Receivable Agreement — — — — — (5) (5) Income (loss) before income taxes 1,216 2,133 902 471 (116) (1,139) 3,467 Income tax expense — — — — — (655) (655) Net income (loss) $ 1,216 $ 2,133 $ 902 $ 471 $ (116) $ (1,794) $ 2,812 Income tax expense — — — — — 655 655 Interest expense and related charges (a) 54 (46) (9) (1) 4 898 900 Depreciation and amortization (b) 114 686 1,278 86 — 66 2,230 EBITDA before Adjustments 1,384 2,773 2,171 556 (112) (175) 6,597 60 Table of Contents Year Ended December 31, 2024 Retail Texas East West Asset Closure Eliminations / Corporate and Other Vistra Consolidated Unrealized net (gain) loss resulting from commodity hedging transactions 52 (790) (76) (332) (9) — (1,155) Purchase accounting impacts — 1 (12) — — (14) (25) Impacts of Tax Receivable Agreement (c) — — — — — (5) (5) Non-cash compensation expenses — — — — — 100 100 Transition and merger expenses 2 1 22 — — 111 136 Decommissioning-related activities (d) — 26 (91) 2 — — (63) ERP system implementation expenses 8 7 5 1 2 — 23 Other, net 17 14 (2) 11 2 (111) (69) Adjusted EBITDA $ 1,463 $ 2,032 $ 2,017 $ 238 $ (117) $ (94) $ 5,539 ____________ (a) Includes $53 million of unrealized mark-to-market net gains on interest rate swaps. (b) Includes nuclear fuel amortization of $105 million and $282 million, respectively, in the Texas and East segments. (c) Includes $10 million gain recognized on the repurchase of TRA Rights in the year ended December 31, 2024. (d) Represents net of all NDT (income) loss of the PJM nuclear facilities, ARO accretion expense for operating assets and ARO remeasurement impacts for operating assets. For the year ended December 31, 2024, the Texas and East segments include nuclear PTC revenue estimates of $281 million and $264 million, respectively. See Note 4 to the Financial Statements for additional information. The following table presents Net income (loss), EBITDA, and Adjusted EBITDA for the year ended December 31, 2023: Year Ended December 31, 2023 Retail Texas East West Asset Closure Eliminations / Corporate and Other Vistra Consolidated (in millions) Operating revenues $ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ (6,576) $ 14,779 Fuel, purchased power costs, and delivery fees (9,046) (2,028) (2,730) (328) (3) 6,578 (7,557) Operating costs (123) (917) (528) (58) (74) (2) (1,702) Depreciation and amortization (102) (550) (703) (79) — (68) (1,502) Selling, general, and administrative expenses (858) (140) (127) (24) (34) (125) (1,308) Impairment of long-lived assets — — (49) — — — (49) Operating income (loss) 443 344 1,753 425 (111) (193) 2,661 Other income 1 35 4 21 110 86 257 Other deductions — (2) (5) — — (7) (14) Interest expense and related charges (20) 21 (2) 8 (5) (742) (740) Impacts of Tax Receivable Agreement — — — — — (164) (164) Income (loss) before income taxes 424 398 1,750 454 (6) (1,020) 2,000 Income tax expense — — (1) — — (507) (508) Net income (loss) $ 424 $ 398 $ 1,749 $ 454 $ (6) $ (1,527) $ 1,492 Income tax expense — — 1 — — 507 508 Interest expense and related charges (a) 20 (21) 2 (8) 5 742 740 Depreciation and amortization (b) 102 641 703 79 — 68 1,593 EBITDA before Adjustments 546 1,018 2,455 525 (1) (210) 4,333 Unrealized net (gain) loss resulting from commodity hedging transactions 586 813 (1,586) (267) (36) — (490) 61 Table of Contents Year Ended December 31, 2023 Retail Texas East West Asset Closure Eliminations / Corporate and Other Vistra Consolidated Impacts of Tax Receivable Agreement (c) — — — — — 135 135 Non-cash compensation expenses — — — — — 78 78 Transition and merger expenses — 1 2 — — 47 50 Impairment of long-lived assets — — 49 — — — 49 PJM capacity performance default impacts (d) — — 9 — — — 9 Winter Storm Uri impacts (e) (52) 4 — — — — (48) Other, net 25 (2) 72 5 (2) (113) (15) Adjusted EBITDA $ 1,105 $ 1,834 $ 1,001 $ 263 $ (39) $ (63) $ 4,101 ____________ (a) Includes $36 million of unrealized mark-to-market net losses on interest rate swaps. (b) Includes nuclear fuel amortization of $91 million in the Texas segment. (c) Includes $29 million gain recognized on the repurchase of TRA Rights in December 2023. (d) Represents estimate of anticipated market participant defaults or settlements on initial PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott. (e) Adjusted EBITDA impacts of Winter Storm Uri reflects the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and a reduction in the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm. GAAP net income increased $1.32 billion to net income of $2.812 billion in the year ended December 31, 2024 compared to the year ended December 31, 2023. The primary drivers for the increase in GAAP net income include: Favorable impacts: • An increase of $665 million in unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down more significantly in Texas relative to our hedge positions in the year ended December 31, 2024 as compared to the year ended December 31, 2023. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below. • Addition of Energy Harbor in March 2024 with results reflected in the East and Retail segments. • An increase of $545 million in PTC revenues due to the nuclear PTC established by the IRA including $281 million and $264 million recognized in Texas and East, respectively. See Note 4 for additional information. • An increase in retail income driven by an increase in customer counts and higher margins. • Expiration of legacy Vistra default service contracts in the East segment which resulted in higher-than-expected migration of customers at rates below prevailing wholesale market prices in the year ended December 31, 2023. • A decrease of approximately $160 million of accretion and remeasurement expenses associated with the TRA obligation driven by the acquisition of substantially all TRA rights between December 2023 and February 2024. Unfavorable impacts: • Increase in depreciation and amortization expense driven by addition of assets acquired from Energy Harbor and reflected in East. • Increase in interest expense driven by higher average borrowings and unrealized mark to market losses on interest rate swaps. • Increase in selling, general, and administrative expenses in Retail segment and Corp. and Other driven primarily by the addition of Energy Harbor. • Increase in income tax expense driven by higher income. 62 Table of Contents Year Ended December 31, Retail Texas East West 2024 2023 2024 2023 2024 2023 2024 2023 Retail electricity sales volumes (GWh): Sales volumes in ERCOT 74,295 70,275 Sales volumes in Northeast/Midwest 59,066 27,147 Total retail electricity sales volumes 133,361 97,422 Production volumes (GWh): Natural gas facilities 44,595 41,849 60,279 60,502 4,175 5,462 Lignite and coal facilities 23,307 26,559 16,938 13,912 Nuclear facilities 19,670 18,893 26,540 Solar facilities 757 781 Capacity factors: CCGT facilities 58.1 % 55.1 % 62.0 % 62.2 % 46.5 % 61.0 % Lignite and coal facilities 59.0 % 67.4 % 49.1 % 40.4 % Nuclear facilities 93.3 % 89.9 % 89.3 % Weather - percent of normal (a): Cooling degree days 112 % 115 % 112 % 112 % 103 % 96 % 90 % 79 % Heating degree days 78 % 85 % 77 % 88 % 88 % 87 % 119 % 125 % ____________ (a) Reflects cooling degree or heating degree days for the region based on Weather Services International (WSI) data. A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base temperature. Year Ended December 31, Year Ended December 31, 2024 2023 2024 2023 Average Power Price ($MWh) (a): Average Natural gas price ($/MMBtu) (b): ERCOT North Hub $ 25.89 $ 48.30 NYMEX Henry Hub $ 2.25 $ 2.53 ERCOT West Hub $ 27.45 $ 49.45 Houston Ship Channel $ 1.87 $ 2.20 PJM AEP Dayton Hub $ 30.74 $ 30.81 Permian Basin $ 0.08 $ 1.53 PJM Northern Illinois Hub $ 25.46 $ 26.64 Dominion South $ 1.67 $ 1.63 PJM Western Hub $ 33.83 $ 33.07 Tetco ELA $ 2.08 $ 2.27 MISO Indiana Hub $ 31.36 $ 32.98 Chicago Citygate $ 2.12 $ 2.30 ISONE Massachusetts Hub $ 41.47 $ 36.82 TetcoM3 $ 2.07 $ 1.90 New York Zone A $ 32.66 $ 25.68 Algonquin Citygates $ 3.03 $ 2.94 CAISO NP15 $ 40.67 $ 61.37 PG&E Citygate $ 3.09 $ 6.09 ____________ (a) Reflects the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we realized. (b) Reflects the average around-the-clock settled prices for the periods presented and does not reflect costs incurred by us. 63 Table of Contents Adjusted EBITDA for the year ended December 31, 2024 compared to the year ended December 31, 2023 increased by $1.438 billion. The primary drivers for the increase include: Year Ended December 31, 2024 Compared to 2023 Retail (a) Texas East (a) West (in millions) Favorable change in realized revenue net of fuel driven by addition of Energy Harbor, including nuclear PTC revenues from the acquired nuclear facilities and rolloff of negative margin defaults service contracts in East. Favorable change in Texas is driven by nuclear PTC revenues. $ — $ 257 $ 1,570 $ 6 Higher retail margins driven by favorable power supply costs, customer count growth and addition of energy Harbor retail contracts, including acquired default service contracts 425 — — — Favorable impact of less Winter Storm Uri bill credits applied 42 — — — Increase in plant operating costs due primarily to addition of Energy Harbor in East — (52) (490) (11) Change in SG&A and other primarily due to increase in costs related to addition of Energy Harbor in Retail and East (109) (7) (64) (20) Change in Adjusted EBITDA $ 358 $ 198 $ 1,016 $ (25) Increase in depreciation and amortization driven primarily by addition of Energy Harbor assets in East (12) (45) (575) (7) Change in unrealized net gains (losses) on hedging activities (b) 534 1,603 (1,510) 65 Impairment of long-lived assets — — 49 — Decommissioning related activities — (26) 91 (2) PJM capacity performance default impacts — — 9 — Winter Storm Uri impact (52) 4 — — Other (including interest expenses) (36) 1 73 (14) Change in Net income $ 792 $ 1,735 $ (847) $ 17 ___________ (a) Includes amounts associated with operations acquired in the Energy Harbor Merger beginning March 1, 2024. (b ) See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy. Asset Closure Segment — Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 Year Ended December 31, Favorable (Unfavorable) Change 2024 2023 (in millions) Operating revenues $ 1 $ — $ 1 Fuel, purchased power costs, and delivery fees (3) (3) — Operating costs (81) (74) (7) Selling, general, and administrative expenses (43) (34) (9) Operating loss (126) (111) (15) Other income 16 110 (94) Other deductions (2) — (2) Interest expense and related charges (4) (5) 1 Income (loss) before income taxes (116) (6) (110) Net loss $ (116) $ (6) $ (110) Adjusted EBITDA $ (117) $ (39) $ (78) GAAP and Adjusted EBITDA results for the year ended December 31, 2024 are unfavorable compared to the year ended December 31, 2023 primarily due to other income of $89 million from the gain on sale of property in Freestone County, Texas in 2023. 64 Table of Contents Energy-Related Commodity Contracts and Mark-to-Market Activities We entered the 2023 and 2024 calendar years with more than 99% of our expected generation volumes hedged. While settled power prices in 2024 are lower than historical averages, the strategic hedging allowed us to lock in margins above what we would have been able to realize if unhedged and are higher than the margins from hedging for the year ended December 31, 2023, which is driving the increase in realized revenue net of fuel in the generation segments along with the addition of Energy Harbor. The forward power sales are also the drivers of the changes in unrealized gains/losses on hedging activities. As power prices increase/decrease in comparison to what our generation segments have sold forward, the generation segments recognize unrealized losses/gains. The retail segment procures power from the generation segments to serve future load obligations and thus changes in forward power prices have an inverse effect on unrealized mark to market for the retail segment as compared to the generation segments. In 2024, we saw a decrease in forward power prices in all our generation segments compared to our hedged positions which drove material unrealized gains in those segments, partially offset by unrealized losses in our retail segment. In 2023, the non-Texas generation segments also experienced a decrease in forward power prices compared to our hedged positions, which resulted in unrealized gains in those segments partially offset by unrealized losses in our retail segment. In the Texas segment, forward power prices materially increased in the year ended December 31, 2023, which resulted in unrealized losses partially offset by unrealized gains in the Retail segment. The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2024 and 2023. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.155 billion and $490 million in unrealized net gains for the years ended December 31, 2024 and 2023, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. Year Ended December 31, 2024 2023 (in millions) Commodity contract net liability as of January 1 $ (2,740) $ (3,148) Settlements/termination of positions (a) 1,213 1,643 Changes in fair value of positions in the portfolio (b) (58) (1,153) Acquired commodity contracts (c) (50) — Other activity (d) 175 (82) Commodity contract net liability as of December 31 $ (1,460) $ (2,740) ____________ (a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains/(losses) recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. (b) Represents unrealized net gains/(losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. (c) Includes fair value of commodity contracts acquired in the Energy Harbor Merger (see Note 2 to the Financial Statements). (d) Primarily represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME. The following maturity table presents the net commodity contract liability arising from recognition of fair values as of December 31, 2024, scheduled by the source of fair value and contractual settlement dates of the underlying positions. Maturity dates of unrealized commodity contract net liability as of December 31, 2024 Source of Fair Value Less than 1 year 1-3 years 4-5 years Excess of 5 years Total (in millions) Prices actively quoted $ (205) $ 11 $ (1) $ — $ (195) Prices provided by other external sources (423) (91) 1 — (513) Prices based on models (162) (507) (75) (8) (752) Total $ (790) $ (587) $ (75) $ (8) $ (1,460) 65 Table of Contents We have engaged in natural gas hedging activities to mitigate the risk of higher or lower wholesale electricity prices that have corresponded to increases or declines in natural gas prices. When natural gas prices are elevated or depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales. Estimated hedging levels for generation volumes in our Texas, East and West segments as of December 31, 2024 were as follows: 2025 2026 Nuclear/Renewable/Coal Generation: Texas 100 % 100 % East 84 % 55 % Natural Gas Generation: Texas 100 % 57 % East 100 % 77 % West 100 % 37 % Financial Condition Cash Flows Operating Cash Flows Cash provided by operating activities totaled $4.563 billion and $5.453 billion for the years ended December 31, 2024 and 2023, respectively. The unfavorable change of $890 million was primarily driven by $1.06 billion less of a decrease in net margin deposits (returns of cash deposits related to commodity contracts which support our hedging strategy) in the year ended December 31, 2024 as compared to the year ended December 31, 2023. The unfavorable change in margin deposits is partially offset by an increase in cash from realized operating income primarily due to the addition of Energy Harbor. Depreciation and amortization — Depreciation and amortization expense, as reported as a reconciling adjustment in the consolidated statements of cash flows, exceeded the amount reported in the consolidated statements of operations by $788 million, $454 million, and $451 million for the years ended December 31, 2024, 2023, and 2022, respectively. This difference represents amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent with industry practice, as well as the amortization of intangible net assets and liabilities. These are reported under various other line items in the consolidated statements of operations, including operating revenues, fuel and purchased power costs, and delivery fees (see Note 7 to the Financial Statements). 66 Table of Contents Investing Cash Flows Cash used in investing activities totaled $5.276 billion and $2.145 billion for the years ended December 31, 2024 and 2023, respectively. The increase of $3.131 billion was driven primarily by the $3.1 billion used to fund the Energy Harbor Merger. Year Ended December 31, Increase (Decrease) 2024 2023 (in millions) Capital expenditures, including LTSA prepayments $ (801) $ (764) (37) Nuclear fuel purchases (477) (214) (263) Growth and development expenditures (800) (698) (102) Total capital expenditures (2,078) (1,676) (402) Energy Harbor acquisition (net of cash acquired) (3,065) — (3,065) Net sales (purchases) of environmental allowances (453) (571) 118 Net sales of (investments in) nuclear decommissioning trust fund securities (23) (23) 0 Proceeds from sales of property, plant, and equipment, including nuclear fuel 196 115 81 Proceeds from sales of transferable ITCs 150 — 150 Other investing activity (3) 10 (13) Cash used in investing activities $ (5,276) $ (2,145) $ (3,131) Financing Cash Flows Cash used in financing activities totaled $1.604 billion and $294 million for the year ended December 31, 2024 and 2023, respectively. The increase of $1.31 billion was primarily driven by the $1.748 billion paid to Avenue and Nuveen in connection with the purchase of their noncontrolling interests in Vistra Vision and the $180 million of dividends we paid to them. These cash outflows were partially offset by an $890 million increase in net new borrowings, as detailed below. Year Ended December 31, Increase (Decrease) 2024 2023 (in millions) Share repurchases $ (1,266) $ (1,245) $ (21) Issuances of long-term debt 3,817 2,498 1,319 Other net long-term borrowings (repayments) (2,287) (33) (2,254) Net short-term borrowings (repayments) — (650) 650 Net borrowings (repayments) under the accounts receivable financing facilities 750 (425) 1,175 Dividends paid to common stockholders (305) (313) 8 Dividends paid to preferred stockholders (173) (150) (23) Dividends paid to noncontrolling and redeemable noncontrolling interest holders (180) — (180) Payment for acquisition of noncontrolling interest (1,748) — (1,748) TRA Repurchase and tender offer — return of capital (122) — (122) Other financing activity (90) 24 (114) Cash used in financing activities $ (1,604) $ (294) $ (1,310) Debt Activity We remain committed to a strong balance sheet and have continued to state our objective to reduce consolidated net leverage. We also intend to maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities. In May 2025, $744 million of 5.125% Senior Secured Notes will reach maturity. We plan to fund this upcoming principal payment using a combination of proceeds from the senior secured notes issued in December 2024 and cash on hand. Increases in interest rates have resulted in, and will likely continue to result in, increased borrowing costs. 67 Table of Contents See Note 9 to the Financial Statements for additional information. Available Liquidity The following table summarizes changes in available liquidity for the year ended December 31, 2024: December 31, 2024 December 31, 2023 Change (in millions) Cash and cash equivalents (a) $ 1,188 $ 3,485 $ (2,297) Vistra Operations Credit Facilities — Revolving Credit Facility (b) 2,162 1,213 949 Vistra Operations — Commodity-Linked Facility (c) 771 1,101 (330) Total available liquidity (d)(e) $ 4,121 $ 5,799 $ (1,678) ____________ (a) See the consolidated statements of cash flows in the Financial Statements and Cash Flows above for details of the decrease in cash and cash equivalents for the year ended December 31, 2024. The decrease includes $3.1 billion that was used to fund the Energy Harbor Merger. (b) The increase in availability for the year ended December 31, 2024 was driven by a $684 million decrease in letters of credit outstanding under the facility and the October 2024 amendment to the Revolving Credit Facility which, among other things, increased the revolving credit commitments by $265 million (see Note 9 to the Financial Statements). (c) As of December 31, 2024 and 2023, the borrowing bases were less than the facility limits of $1.75 billion and $1.575 billion, respectively. As of December 31, 2024, available capacity reflects the borrowing base of $771 million and no cash borrowings. As of December 31, 2023, available capacity reflects the borrowing base of $1.101 billion and no cash borrowings. (d) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 9 to the Financial Statements for additional information. (e) Excludes any additional letters of credit that may be issued under the Secured LOC Facilities or the Alternative LOC Facilities. See Note 9 to the Financial Statements for additional information. We believe that we will have access to sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months, including the upcoming payments associated with the acquisition of Nuveen's noncontrolling interest in Vistra Vision discussed in Note 9 to the Financial Statements. Our operational cash flows tend to be seasonal and weighted toward the second half of the year. Interest payments on long-term debt, after taking into account interest rate swaps, are expected to total approximately $905 million in 2025, $1.595 billion in 2026-2027, $1.180 billion in 2028-2029 and $1.305 billion thereafter. See Note 9 to the Financial Statements for additional information. Our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments, are expected to total approximately $3.270 billion in 2025, $2.650 billion in 2026-2027, $1.490 billion in 2028-2029 and $450 million thereafter. See Notes 10 and 15 to the Financial Statements for additional information. Capital Expenditures Estimated 2025 capital expenditures and nuclear fuel purchases as of December 31, 2024 total approximately $2.275 billion and include: • $925 million for investments in generation and mining facilities; • $725 million for solar and energy storage development; • $300 million for nuclear fuel purchases; and • $325 million for other growth expenditures. 68 Table of Contents Liquidity Effects of Commodity Hedging and Trading Activities We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit, Eligible Assets (see Note 8 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 9 to the Financial Statements for additional information. Exchange cleared transactions typically require initial margin ( i.e. , the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin ( i.e. , the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors, including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other business purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted. As of December 31, 2024, we received or posted cash, letters of credit and Eligible Assets for commodity hedging and trading activities as follows: • $841 million in cash and Eligible Assets has been posted with counterparties as compared to $1.244 billion posted as of December 31, 2023; • $49 million in cash has been received from counterparties as compared to $45 million received as of December 31, 2023; • $2.560 billion in letters of credit have been posted with counterparties as compared to $2.408 billion posted as of December 31, 2023; and • $131 million in letters of credit have been received from counterparties as compared to $143 million received as of December 31, 2023. See Collateral Support Obligations below for information related to collateral posted in accordance with the PUCT and ISO/RTO rules. Income Tax Payments In the next 12 months, we expect to make approximately $31 million in federal income tax payments, $81 million in state income tax payments and $2 million in TRA payments, offset by $14 million in state tax refunds. For the year ended December 31, 2024, there were $5 million federal income tax payments, $59 million in state income tax payments, $9 million in state income tax refunds and no TRA payments. Capitalization Our capitalization ratios consisted of 73% and 70% long-term debt (less amounts due currently) and 27% and 30% stockholders' equity at December 31, 2024 and 2023, respectively. Total long-term debt (including amounts due currently) to capitalization was 75% and 73% at December 31, 2024 and 2023, respectively. 69 Table of Contents Financial Covenants The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and revolving letters of credit outstanding (excluding all undrawn revolving letters of credit and cash collateralized backstopped revolving letters of credit) exceed 35% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). In addition, each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). Although the period ended December 31, 2024 was not a compliance period, we would have been in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants if they were required to be tested at such time. See Note 9 to the Financial Statements for additional information. Collateral Support Obligations The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation of our assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts. The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of December 31, 2024, Vistra has posted letters of credit in the amount of $86 million with the PUCT, which is subject to adjustments. The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $960 million in the form of letters of credit, $70 million in the form of a surety bond and $3 million of cash as of December 31, 2024 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs). Material Cross Default/Acceleration Provisions Certain of our contractual arrangements contain provisions that could result in an event of default if there were a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions. A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greatest of $1.0 billion, 17.5% of Consolidated EBITDA and 2.50% of Consolidated Total Assets, may result in a cross default under the Vistra Operations Credit Facilities and the Commodity-Linked Facility. Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.475 billion and zero, respectively, as of December 31, 2024. Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross-default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness equal to or above a threshold defined in the applicable agreement that results in the acceleration of such debt, would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled. 70 Table of Contents Under the Vistra Operations Senior Unsecured Indentures, the Vistra Operations Senior Secured Indenture and the Indenture governing the 7.233% Senior Secured Notes, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the 7.233% Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Commodity-Linked Facility and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto. Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which may vary by contract. The Receivables Facility contains a cross-default provision. The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC, TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), and Vistra or any of their respective subsidiaries fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, in the case of Vistra Operations, and in a principal amount of at least $50 million, in the case of TXU Energy or any of the other Originators, after the expiration of any applicable grace period, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity. If this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables Facility may be terminated. The Repurchase Facility contains a cross-default provision. The cross-default provision applies, among other instances, if an event of default (or similar event) occurs under the Receivables Facility or the Vistra Operations Credit Facilities. If this cross-default provision is triggered, a termination event under the Repurchase Facility would occur and the Repurchase Facility may be terminated. Under the Secured LOC Facilities, a default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Secured LOC Facilities. In addition, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Secured LOC Facilities. Under the Alternative LOC Facilities, a default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Alternative LOC Facilities. In addition, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount exceeding the threshold above, may result in a termination of the Alternative LOC Facilities. Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes, the 6.875% Senior Unsecured Notes, the 6.950% Senior Secured Notes and the 6.000% Senior Secured Notes, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the respective notes and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto. A default by Vistra Zero Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greatest of $100 million, 75% of Consolidated EBITDA and 6% of Consolidated Total Assets, may result in a cross default under the Vistra Zero Credit Agreement. Such a default would allow the lenders under such facility to accelerate the maturity of outstanding balances under such facility, which totaled approximately $697 million as of December 31, 2024. 71 Table of Contents A default by BCOP or any of its subsidiary guarantors in respect of certain provisions defined in the applicable agreement may result in a cross default under the BCOP Credit Agreement. Such a default would allow the lenders under such facility to accelerate the maturity of outstanding balances under such facility. In addition, the interest rate swap agreements that are secured with a lien on BCOP and its subsidiary guarantors' assets on a pari passu basis with the BCOP Credit Agreement contain cross-default provisions, where an event of a default by BCOP or any of its subsidiary guarantors that results in the acceleration of such debt, would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with BCOP and require all outstanding obligations under such agreement to be settled. Under the Nuveen UPA, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the UPA. Such a default would result in the payment obligations under the Nuveen UPA of Vistra Vision Holdings and/or any guarantor thereunder becoming immediately due and payable. Guarantees See Note 15 to the Financial Statements for additional information. Commitments and Contingencies See Note 15 to the Financial Statements for additional information. Changes in Accounting Standards See Note 1 to the Financial Statements for additional information.