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 our 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 2 Form 10-K for a discussion of our financial condition and results of operations for the year ended December 31, 2021 and for the year ended December 31, 2022 compared to the year ended December 31, 2021, which is incorporated here by reference. All dollar amounts in the tables in the following discussion and analysis are stated in millions of U.S. dollars unless otherwise indicated. Significant Activities and Events, and Items Influencing Future Performance 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. 50 Table of Contents 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. 51 Table of Contents • 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. 52 Table of Contents 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: 2023-2024 2024-2025 (average price per MW-day) RTO zone $ 34.13 $ 28.92 ComEd zone 34.13 28.92 MAAC zone 49.49 49.49 EMAAC zone 49.49 54.95 ATSI zone 34.13 28.92 DEOK zone 34.13 96.24 Our capacity sales in PJM, net of purchases, aggregated by planning year and capacity type through planning year 2024-2025, are as follows: 2023-2024 2024-2025 East Segment Sunset Segment East Segment Sunset Segment CP auction capacity sold, net (MW) 5,811 1,667 5,567 1,338 Bilateral capacity sold, net (MW) 378 166 400 38 Total segment capacity sold, net (MW) 6,189 1,833 5,967 1,376 Average price per MW-day $ 38.61 $ 36.82 $ 36.80 $ 75.11 53 Table of Contents 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 2023 - 2024 Price per kW-month $ 3.83 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: East Segment Winter 2023 - 2024 Summer 2024 Winter 2024 - 2025 Summer 2025 Winter 2025 - 2026 Auction capacity sold (MW) 12 — — — — Bilateral capacity sold (MW) 1,132 873 591 175 59 Total capacity sold (MW) 1,144 873 591 175 59 Average price per kW-month $ 2.27 $ 3.80 $ 3.44 $ 4.10 $ 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: 2023-2024 2024-2025 2025-2026 2026-2027 2027-2028 Price per kW-month $ 2.00 $ 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 2023-2024 2024-2025 2025-2026 2026-2027 2027-2028 Auction capacity sold (MW) 3,213 3,103 3,032 2,836 3,261 Bilateral capacity sold (MW) 22 78 78 58 8 Total capacity sold (MW) 3,235 3,181 3,110 2,894 3,269 Average price per kW-month $ 2.22 $ 3.12 $ 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: 2023-2024 Price per MW-day $ 9.25 MISO capacity sales through planning year 2026-2027 are as follows: Sunset Segment 2023-2024 2024-2025 2025-2026 2026-2027 Bilateral capacity sold in MISO (MW) 1,702 984 423 101 Total MISO segment capacity sold (MW) 1,702 984 423 101 Average price per kW-month $ 4.36 $ 4.34 $ 4.94 $ 4.59 54 Table of Contents 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: West Segment 2024 2025 2026 2027 Bilateral capacity sold (Avg MW) 1,880 1,770 1,250 750 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. Critical Accounting Estimates We follow accounting principles generally accepted in the U.S. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting estimates that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies. 55 Table of Contents Derivative Instruments and Mark-to-Market Accounting We enter into contracts for the purchase and sale of energy-related commodities, and also enter into 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 on our consolidated balance sheets and could result in a material change to the unrealized gains or losses recorded in our consolidated statements of operations. We estimate fair value as described in Note 16 to the Financial Statements. 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 not subject to mark-to-market accounting if the NPNS election is made 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 due to changes in estimates, the related contract would be recorded on the balance sheet at fair value with immediate recognition through earnings. See Note 17 to the Financial Statements for further discussion regarding derivative instruments. 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. 56 Table of Contents 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 7 to the Financial Statements for further discussion of income tax matters. Accounting for Tax Receivable Agreement (TRA) On the Effective Date, Vistra entered into the TRA with a transfer agent. Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Vistra reflected the obligation associated with TRA Rights at fair value in the amount of $574 million as of the Effective Date related to these future payment obligations. In December 2023, we repurchased approximately 74% of the TRA Rights to receive payments under the TRA from a select group of registered holders of the TRA Rights. Also, during the year ended December 31, 2023, we recorded an increase to the carrying value of the TRA obligation totaling $82 million as a result of adjustments to forecasted taxable income due to increases in longer-term commodity price forecasts. As of December 31, 2023, the TRA obligation has been adjusted to $171 million, and the expected undiscounted federal and state payments under the TRA is estimated to be approximately $350 million. After giving effect to the January 2024 additional repurchases and the January and February 2024 early tender offer repurchases, we have repurchased an aggregate 98% of the original outstanding TRA Rights, of which 10,430,083 TRA Rights remain outstanding as of the Early Tender Date. The TRA obligation value is the discounted amount of projected payments to be made each year under the TRA, based on certain assumptions, including but not limited to: • the amount of tax basis related to (i) the Lamar and Forney acquisition and (ii) step-up resulting from the PrefCo Preferred Stock Sale (which is estimated to be approximately $5.5 billion) and the allocation of such tax basis step-up among the assets subject thereto; • the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most of such assets; • a blended federal/state corporate income tax rate in all future years of 23.2%; • future taxable income by year for future years; • the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of (i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA in the tax year in which such deductions arise; • a discount rate of 15%, which represented our view at the Effective Date of the rate that a market participant would use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of Emergence; and • additional states that Vistra now operates in, the relevant tax rates of those states and how income will be apportioned to those states. There may be significant changes, which may be material, to the estimate of the related liability due to various reasons including changes in federal and state tax laws and regulations, changes in estimates of the amount or timing of future consolidated taxable income, utilization of acquired net operating losses, reversals of temporary book/tax differences and other items. Changes in those estimates are recognized as adjustments to the related TRA obligation, with offsetting impacts recorded in the consolidated statements of operations as Impacts of Tax Receivable Agreement. See Note 8 to the Financial Statements. Asset Retirement Obligations (ARO) As part of business combination accounting, new fair values were established for all AROs assumed in the Dynegy Merger. A liability is initially recorded at fair value for an ARO associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets. These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, and remediation or closure of coal ash basins. In estimating the ARO liability, we are required to make significant estimates and assumptions. 57 Table of Contents 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 (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. 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 for December 31, 2023, we have included an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate Comanche Peak Units 1 and 2 through 2050 and 2053, respectively. The costs to ultimately decommission the facility are recoverable through the regulatory rate making process as part of Oncor's delivery fees and therefore changes in estimates of the ARO do not impact Vistra's earnings. The estimates and assumptions required for the mining land reclamation related to lignite mining, such as costs to fill in mining pits and interpretation of the mining permit closure requirements, are complex and require a significant amount of judgment. To develop the estimate of costs to fill in mining pits, we utilize a complex proprietary model to estimate the volume of the pit. A significant portion of the estimate is associated with the Asset Closure segment, thus related to closed facilities with changes in the estimate recorded to our consolidated statements of operations. These obligations are adjusted on a regular basis to reflect the passage of time and to incorporate revisions to the following significant estimates and assumptions: • estimation of dates for retirement, which can be dependent on environmental and other legislation; • amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities; • discount rates; • cost escalation factors; • market risk premium; • inflation rates; and • if applicable, past experience with government regulators regarding similar obligations. For the next five years, Vistra is projected to spend approximately $516 million (on a nominal basis) to achieve its mining reclamation and other coal ash remediation objectives. During the years ended December 31, 2023, 2022 and 2021, we transferred zero, $61 million and zero, respectively, in ARO obligations to third parties for remediation. Any remaining unpaid third-party obligation was reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets. See Note 22 to the Financial Statements for additional discussion of ARO obligations and adjustments made to the ARO obligation estimates during the years ended December 31, 2023, 2022 and 2021. Impairment of Goodwill and Other Long-Lived Assets We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. For our generation assets, possible indications include an expectation of continuing long-term declines in natural gas prices and/or Market Heat Rates or 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. 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 related to an asset or group of assets. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing. See Note 22 to the Financial Statements for discussion of impairments of long-lived assets recorded in the years ended December 31, 2022, 2021 and 2020. 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, through considering specific assumptions for 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. 58 Table of Contents 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 natural gas and electricity prices, forward capacity prices, Market Heat Rates, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures and forecasted fuel prices. Another key assumption in the income approach is 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. Additional material impairments related to our generation facilities may occur in the future if forward wholesale electricity prices decline in the markets in which we operate in or if additional environmental regulations increase the cost of producing electricity at our generation facilities. Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield, Dynegy Energy Services, TriEagle Energy, Public Power and U.S. Gas & Electric, respectively, are required to be evaluated for impairment at least annually (we have selected October 1 as our annual impairment test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry. As of December 31, 2023, our goodwill balances totaled $2.461 billion and $122 million for our Retail reporting unit and Texas Generation reporting unit, respectively. Under this goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value, the excess carrying value is written off as an impairment charge. Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill is more likely than not less than the fair value of that reporting unit. If the entity determines the carrying value, including goodwill, is not more likely greater than the fair value, no further testing of goodwill for impairment is required. On the most recent goodwill testing date, we performed a qualitative assessment and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2023. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, interest rates and changes in reporting unit book value. As of December 31, 2023, intangible assets with indefinite useful lives related to our retail trade names totaled $1.341 billion. Under this impairment analysis, if at the assessment date, a retail trade name's carrying value exceeds its estimated fair value, the excess carrying value is written off as an impairment charge. Accounting standards allow a company to qualitatively assess if the carrying value of our retail trade name intangible assets is more likely than not less than the fair value. 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 retail trade names exceeded their carrying value at October 1, 2023. Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest rates. Results of Operations Net income (loss) attributable to Vistra common stock increased $2.6 billion to income of $1.5 billion for the year ended December 31, 2023 from a loss of $1.2 billion for the year ended December 31, 2022. 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. 59 Table of Contents 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 our 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, 2023 Compared to Year Ended December 31, 2022 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 Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Operating revenues $ 10,572 $ 3,823 $ 4,215 $ 914 $ 1,831 $ — $ (6,576) $ 14,779 Fuel, purchased power costs and delivery fees (9,046) (1,951) (2,031) (328) (776) (3) 6,578 (7,557) Operating costs (123) (894) (297) (58) (254) (74) (2) (1,702) Depreciation and amortization (102) (544) (647) (79) (62) — (68) (1,502) Selling, general and administrative expenses (858) (134) (82) (24) (51) (34) (125) (1,308) Impairment of long-lived assets — — — — (49) — — (49) Operating income (loss) 443 300 1,158 425 639 (111) (193) 2,661 Other income 1 35 3 21 1 110 86 257 Other deductions — (2) — — (5) — (7) (14) Interest expense and related charges (20) 21 — 8 (2) (5) (742) (740) Impacts of Tax Receivable Agreement — — — — — — (164) (164) Income (loss) before income taxes 424 354 1,161 454 633 (6) (1,020) 2,000 Income tax expense — — (1) — — — (507) (508) Net income (loss) $ 424 $ 354 $ 1,160 $ 454 $ 633 $ (6) $ (1,527) $ 1,492 60 Table of Contents Year Ended December 31, 2023 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Income tax expense — — 1 — — — 507 508 Interest expense and related charges (a) 20 (21) — (8) 2 5 742 740 Depreciation and amortization (b) 102 635 647 79 62 — 68 1,593 EBITDA before Adjustments 546 968 1,808 525 697 (1) (210) 4,333 Unrealized net (gain) loss resulting from commodity hedging transactions 586 799 (1,117) (267) (455) (36) — (490) Impacts of Tax Receivable Agreement (c) — — — — — — 135 135 Non-cash compensation expenses — — — — — — 78 78 Transition and merger expenses — 1 1 — 1 — 47 50 Impairment of long-lived assets — — — — 49 — — 49 PJM capacity performance default impacts (d) — — 3 — 6 — — 9 Winter Storm Uri impacts (e) (52) 4 — — — — — (48) Other, net 25 (2) 12 5 60 (2) (113) (15) Adjusted EBITDA $ 1,105 $ 1,770 $ 707 $ 263 $ 358 $ (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 (see Note 8 to the Financial Statements). (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) Includes the application of bill credits. The Company incentivized certain large commercial and industrial customers to curtail their usage during Winter Storm Uri by providing bill credits for use in future periods. The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance. We estimate remaining bill credit amounts to be applied in future periods for 2024 (approximately $11 million) and 2025 (approximately $26 million). The following table presents net income (loss), EBITDA and adjusted EBITDA for the year ended December 31, 2022: Year Ended December 31, 2022 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Operating revenues $ 9,455 $ 3,733 $ 3,706 $ 336 $ 868 $ 384 $ (4,754) $ 13,728 Fuel, purchased power costs and delivery fees (7,169) (2,968) (3,546) (481) (670) (322) 4,755 (10,401) Operating costs (143) (808) (255) (42) (251) (145) (1) (1,645) Depreciation and amortization (145) (537) (706) (42) (66) (31) (69) (1,596) Selling, general and administrative expenses (826) (131) (66) (21) (35) (44) (66) (1,189) Impairment of long-lived assets — — — — (74) — — (74) Operating income (loss) 1,172 (711) (867) (250) (228) (158) (135) (1,177) 61 Table of Contents Year Ended December 31, 2022 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Other income 2 78 2 6 — 16 13 117 Other deductions (2) (2) — — 1 (2) 1 (4) Interest expense and related charges (14) 20 (3) 6 (3) (3) (371) (368) Impacts of Tax Receivable Agreement — — — — — — (128) (128) Income (loss) before income taxes 1,158 (615) (868) (238) (230) (147) (620) (1,560) Income tax benefit — — — — — — 350 350 Net income (loss) $ 1,158 $ (615) $ (868) $ (238) $ (230) $ (147) $ (270) $ (1,210) Income tax benefit — — — — — — (350) (350) Interest expense and related charges (a) 14 (20) 3 (6) 3 3 371 368 Depreciation and amortization (b) 145 623 706 42 66 31 69 1,682 EBITDA before Adjustments 1,317 (12) (159) (202) (161) (113) (180) 490 Unrealized net (gain) loss resulting from commodity hedging transactions (291) 1,610 759 351 100 (19) — 2,510 Generation plant retirement expenses — — — — 7 (3) — 4 Fresh start/purchase accounting impacts — (2) (1) — 9 — — 6 Impacts of Tax Receivable Agreement — — — — — — 128 128 Non-cash compensation expenses — — — — — — 65 65 Transition and merger expenses 7 — 1 — — — 5 13 Impairment of long-lived assets — — — — 74 — — 74 Winter Storm Uri (c) (141) (178) — — — — — (319) Other, net 31 20 8 3 13 10 (62) 23 Adjusted EBITDA $ 923 $ 1,438 $ 608 $ 152 $ 42 $ (125) $ (44) $ 2,994 ____________ (a) Includes $250 million of unrealized mark-to-market net gains on interest rate swaps. (b) Includes nuclear fuel amortization of $86 million in the Texas segment. (c) Adjusted EBITDA impacts of Winter Storm Uri reflects $183 million related to 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 and $144 million related to the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri. The adjustment for ERCOT default uplift charges relates to (i) ERCOT receiving payments that reduced the market wide default balance and (ii) the fourth quarter 2022 derecognition of the remaining default balance in connection with a settlement between Brazos and ERCOT. Operating income increased $3.838 billion to $2.661 billion in the year ended December 31, 2023 compared to the year ended December 31, 2022. Results for the year ended December 31, 2023 were favorably impacted by $490 million in pre-tax unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down in the year ended December 31, 2023 compared to $2.510 billion in pre-tax unrealized mark-to-market losses on commodity derivative positions due to power and natural gas forward market curves moving up materially in the year ended December 31, 2022. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below. 62 Table of Contents Operating results for the year ended December 31, 2023, compared to the year ended December 31, 2022 were favorably impacted by strong plant operating performance allowing us to realize the value created by our comprehensive hedging strategy, partially offset by lower than expected retail sales volumes due to unfavorable weather. The following table presents operational performance of our retail and generation segments. Year Ended December 31, Retail Texas East West Sunset 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 Retail sales volumes (GWh): Retail electricity sales volumes: Sales volumes in ERCOT 70,275 65,207 Sales volumes in Northeast/Midwest 27,147 32,882 Total retail electricity sales volumes 97,422 98,089 Production volumes (GWh): Natural gas facilities 41,849 34,784 60,502 54,569 5,462 5,134 Lignite and coal facilities 23,899 25,211 16,572 21,824 Nuclear facilities 18,893 19,688 Solar facilities 781 822 Capacity factors: CCGT facilities 55.1 % 48.8 % 62.2 % 57.2 % 61.0 % 57.1 % Lignite and coal facilities 70.9 % 74.8 % 41.3 % 54.4 % Nuclear facilities 89.9 % 93.6 % Weather - percent of normal (a): Cooling degree days 115 % 111 % 112 % 109 % 90 % 107 % 79 % 107 % 112 % 113 % Heating degree days 85 % 108 % 88 % 123 % 87 % 99 % 125 % 109 % 86 % 99 % ____________ (a) Reflects cooling degree or heating degree days for the region based on Weather Services International (WSI) data. Year Ended December 31, Year Ended December 31, 2023 2022 2023 2022 Market pricing Average Market On-Peak Power Prices ($MWh) (b): Average ERCOT North power price ($/MWh) $ 48.30 $ 62.17 PJM West Hub $ 39.22 $ 83.59 AEP Dayton Hub $ 36.22 $ 79.51 Average NYMEX Henry Hub natural gas price ($/MMBtu) $ 2.53 $ 6.39 NYISO Zone C $ 30.38 $ 65.54 Massachusetts Hub $ 41.02 $ 92.17 Average natural gas price (a): Indiana Hub $ 38.92 $ 82.03 TetcoM3 ($/MMBtu) $ 1.90 $ 6.81 Northern Illinois Hub $ 32.67 $ 71.76 Algonquin Citygates ($/MMBtu) $ 2.94 $ 9.16 CAISO NP15 $ 63.92 $ 93.12 ____________ (a) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. (b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized. 63 Table of Contents For the year ended December 31, 2023, other income totaled $257 million driven by a gain of $89 million from the sale of property in Freestone County, Texas recorded in the Asset Closure Segment and $86 million in interest income due to holding a material cash balance anticipating the Energy Harbor transaction closing. For the year ended December 31, 2022, other income totaled $117 million driven by insurance proceeds of $70 million which primarily consists of business interruption claim proceeds recorded in the Texas segment. See Note 22 to the Financial Statements. The increase in consolidated interest expense and related charges of $372 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, is primarily due to (a) unrealized mark-to-market losses on interest rate swaps of $36 million in 2023 compared to unrealized mark-to-market gains on interest rate swaps of $250 million in 2022 due to less volatility in interest rates in the year ended December 31, 2023 compared to the year ended December 31, 2022, (b) an increase in interest paid/accrued of $63 million driven by higher effective interest rates in 2023 and (c) $21 million of commitment fees related to the Commitment Letter in the year ended December 31, 2023. See Note 22 to the Financial Statements. The following table presents additional changes to net income (loss) and Adjusted EBITDA for the year ended December 31, 2023 compared to the year ended December 31, 2022. Year Ended December 31, 2023 Compared to 2022 Retail Texas East West Sunset Favorable change in realized revenue net of fuel driven by effectiveness of comprehensive hedging $ — $ 483 $ 153 $ 113 $ 357 Higher margins driven by increase in customers and interyear timing of power supply costs 290 — — — — Winter Storm Uri bill credit runoff 92 — — — — Impacts of mild weather in 2023 (160) — — — — Change in operating costs due primarily to change in generation volumes — (86) (40) (17) 1 Change in SG&A and other (40) (65) (14) 15 (42) Change in Adjusted EBITDA $ 182 $ 332 $ 99 $ 111 $ 316 Favorable/(unfavorable) change in depreciation and amortization 43 (12) 59 (37) 4 Change in unrealized net gains (losses) on hedging activities (877) 811 1,876 618 555 Impairment of long-lived assets — — — — 25 PJM capacity performance default impacts — — (3) — (6) Winter Storm Uri impact (ERCOT default uplift) (89) (182) — — — Other (including interest expenses) 7 20 (3) — (31) Change in Net income $ (734) $ 969 $ 2,028 $ 692 $ 863 To supplement the amounts and explanations noted above, primary drivers of results for the year ended December 31, 2023 compared to the year ended December 31, 2022 include: • Comprehensive hedging strategy . See Energy-Related Commodity Contracts and Mark-to-Market Activities below. • Winter Storm Uri impacts . 2022 GAAP and Adjusted EBITDA results continued to be materially impacted by Winter Storm Uri. In 2022, a $189 million default uplift liability to ERCOT was extinguished and resulted in net income during the year, but had no impact on Adjusted EBITDA in 2022 as the initial liability incurred in 2021 was excluded from Adjusted EBITDA. • SG&A expenses and other . 2023 is unfavorable compared to 2022 driven primarily by higher incentive compensation in 2023 and insurance recoveries recorded in Texas in 2022. 64 Table of Contents Asset Closure Segment — Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 Year Ended December 31, Favorable (Unfavorable) Change 2023 2022 Operating revenues $ — $ 384 $ (384) Fuel, purchased power costs and delivery fees (3) (322) 319 Operating costs (74) (145) 71 Depreciation and amortization — (31) 31 Selling, general and administrative expenses (34) (44) 10 Operating loss (111) (158) 47 Other income 110 16 94 Other deductions — (2) 2 Interest expense and related charges (5) (3) (2) Income (loss) before income taxes (6) (147) 141 Net loss $ (6) $ (147) $ 141 Adjusted EBITDA $ (39) $ (125) $ 86 Production volumes (GWh) — 9,401 (9,401) For the year ended December 31, 2022, results and volumes for the Asset Closure segment include those from Edwards generation plant that we retired on January 1, 2023 and include unrealized hedging gains related to coal and power derivatives of $19 million. Operating costs for the years ended December 31, 2023 and 2022 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. GAAP and Adjusted EBITDA results for 2023 are favorable to 2022 primarily due to the $89 million gain on sale of land in Freestone County, Texas. Energy-Related Commodity Contracts and Mark-to-Market Activities As forward power prices materially increased in 2022, our generation segments (Texas, East, West and Sunset) aggressively sold forward power for 2023 and future years. While settled power prices in 2023 are lower than 2022, the strategic hedging allowed us to lock in margins for 2023 which resulted in realized revenue net of fuel above what we were able to recognize in 2022 (were mostly hedged going into 2022 so did not recognize the full benefit of settled prices). 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. This is evident in 2022 as material increase in forward power prices drove material unrealized losses in our generation segment, partially offset by unrealized gains in our retail segment. In 2023, forward power prices decreased slightly which resulted in unrealized gains in our generation segments which is partially offset by unrealized losses in our retail segment. 65 Table of Contents The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2023 and 2022. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $490 million in unrealized net gains and $2.51 billion in unrealized net losses for the years ended December 31, 2023 and 2022, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. Year Ended December 31, 2023 2022 Commodity contract net liability at beginning of period $ (3,148) $ (866) Settlements/termination of positions (a) 1,643 1,218 Changes in fair value of positions in the portfolio (b) (1,153) (3,728) Other activity (c) (82) 228 Commodity contract net liability at end of period $ (2,740) $ (3,148) ____________ (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) 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 at December 31, 2023, scheduled by the source of fair value and contractual settlement dates of the underlying positions. Maturity dates of unrealized commodity contract net liability at December 31, 2023 Source of Fair Value Less than 1 year 1-3 years 4-5 years Excess of 5 years Total Prices actively quoted $ (725) $ (207) $ 3 $ — $ (929) Prices provided by other external sources (358) (409) — — (767) Prices based on models (355) (454) (138) (97) (1,044) Total $ (1,438) $ (1,070) $ (135) $ (97) $ (2,740) 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, West and Sunset segments as of December 31, 2023 were as follows: 2024 2025 Nuclear/Renewable/Coal Generation: Texas 96 % 93 % Sunset 96 % 58 % Natural Gas Generation: Texas 89 % 80 % East 99 % 80 % West 100 % 81 % 66 Table of Contents Financial Condition Cash Flows Operating Cash Flows Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 — Cash provided by operating activities totaled $5.453 billion and $485 million in the years ended December 31, 2023 and 2022, respectively. The favorable change of $4.968 billion was primarily driven by (a) a decrease in net margin deposits (return of cash) of $1.899 billion in the year ended December 31, 2023 as compared to an increase in net margin deposits of $1.874 billion in the year ended December 31, 2022 related to commodity contracts which support our comprehensive hedging strategy, including the impacts of cash margin deposits returned and replaced with amounts posted under an affiliate financing agreement (see Note 11 to the Financial Statements) and (b) an increase in cash from operating income exclusive of net margin deposits, partially offset by $544 million of securitization proceeds from ERCOT in the year ended December 31, 2022 (see Note 1 to the Financial Statements). Depreciation and amortization — Depreciation and amortization expense reported as a reconciling adjustment in the consolidated statements of cash flows exceeds the amount reported in the consolidated statements of operations by $454 million, $451 million and $297 million for the years ended December 31, 2023, 2022 and 2021, respectively. The difference represents amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees (see Note 6 to the Financial Statements). Investing Cash Flows Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 — Cash used in investing activities totaled $2.145 billion and $1.239 billion in the years ended December 31, 2023 and 2022, respectively. The increase of $906 million was driven by (a) $543 million in higher net purchases of environmental allowances and (b) a $375 million increase in capital expenditures due primarily to continued development of our solar and energy storage generation facilities (see Note 3 to the Financial Statements), partially offset by $37 million in higher proceeds from the sale of assets driven by our sale of property in Freestone County, Texas in the year ended December 31, 2023. Year Ended December 31, Increase (Decrease) 2023 2022 Capital expenditures, including LTSA prepayments $ (764) $ (628) (136) Nuclear fuel purchases (214) (198) (16) Growth and development expenditures (698) (475) (223) Total capital expenditures (1,676) (1,301) (375) Net sales (purchases) of environmental allowances (571) (28) (543) Net sales of (investments in) nuclear decommissioning trust fund securities (23) (23) 0 Proceeds from sales of property, plant and equipment 115 78 37 Other investing activity 10 35 (25) Cash used in investing activities $ (2,145) $ (1,239) $ (906) 67 Table of Contents Financing Cash Flows Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 — Cash used in financing activities totaled $294 million and $80 million in the years ended December 31, 2023 and 2022, respectively. The $214 million increase in cash used was driven by (a) the net repayment of $1.075 billion in the year ended December 31, 2023 of short-term debt and accounts receivable financing amounts borrowed in the year ended December 31, 2022 driven by changes in collateral posting requirements and (b) $1.5 billion principal amount of senior secured notes issued in May 2022, partially offset by (1) $2.5 billion principal amount of senior secured and senior unsecured notes issued in September 2023 and December 2023, of which $750 million will be used to fund cash tender offers in January 2024, and (2) lower share repurchases in 2023. Year Ended December 31, Increase (Decrease) 2023 2022 Share repurchases $ (1,245) $ (1,949) $ 704 Issuances of senior notes 2,498 1,498 1,000 Other net long-term borrowings (repayments), including the forward capacity agreements (33) (251) 218 Net short-term borrowings (repayments) (650) 650 (1,300) Net borrowings (repayments) under the accounts receivable financing facilities (425) 425 (850) Dividends paid to common stockholders (313) (302) (11) Dividends paid to preferred stockholders (150) (151) 1 Other financing activity 24 — 24 Cash used in financing activities $ (294) $ (80) $ (214) Collateral Financing Agreement With Affiliate On June 15, 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed by the Company that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $450 million. The Trust is not consolidated by Vistra. The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S. Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S. dollars, the Eligible Assets). At the direction of Vistra Operations, the Eligible Assets held by the Trust will be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program. Under the Facility Agreement, Vistra Operations will have the right (Issuance Right), from time to time, to require the Trust to purchase from Vistra Operations up to $450 million aggregate principal amount of Vistra Operations' 7.233% senior secured notes due 2028 (7.233% Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury Strips corresponding to the portion of the issuance right exercised at such time. As of December 31, 2023, all of the Eligible Assets were being utilized to meet a portion of our current and future collateral posting obligations. The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233% Senior Secured Notes to the holders of the P-Caps if its sole assets consist of 7.233% Senior Secured Notes that Vistra Operations is no longer entitled to repurchase. See Note 11 for additional details of the collateral financing agreement with affiliate. Debt Activity We remain committed to a strong balance sheet and have continued to state our objective to reduce our consolidated net leverage. We also intend to maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities. 68 Table of Contents In May 2024 and July 2024, after taking into account the Senior Secured Notes Tender Offer settled in January 2024, $342 million of 4.875% Senior Secured Notes and $1.155 billion of 3.550% Senior Secured Notes, respectively, will reach maturity. We plan to fund these upcoming principal payments using a combination of cash on hand and new debt issuances. Increases in interest rates will likely result in increased borrowing costs. See Note 10 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 12 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt. Available Liquidity The following table summarizes changes in available liquidity for the year ended December 31, 2023: December 31, 2023 December 31, 2022 Change Cash and cash equivalents (a) $ 3,485 $ 455 $ 3,030 Vistra Operations Credit Facilities — Revolving Credit Facility (b) 1,213 1,236 (23) Vistra Operations — Commodity-Linked Facility (c) 1,101 808 293 Total available liquidity (d)(e) $ 5,799 $ 2,499 $ 3,300 ____________ (a) See the Consolidated Statements of Cash Flows in the Financial Statements and Cash Flows above for details of the increase in cash and cash equivalents for the year ended December 31, 2023. The increase includes proceeds from the issuance of $1.75 billion and $750 million principal amount of Vistra Operations senior secured and senior unsecured notes in September 2023 and December 2023, respectively. Proceeds from the September 2023 issuance are expected to be used, together with cash on hand, to fund the Transactions. Proceeds from the December 2023 issuance were used to settle the Senior Secured Notes Tender Offers in January 2024. (b) The decrease in availability for the year ended December 31, 2023 was driven by a $73 million increase in letters of credit outstanding under the facility and the maturity of $200 million of commitments under the Non-Extended Revolving Credit Facility, partially offset by $250 million in net repayments of borrowings under the facility. (c) As of December 31, 2023 and 2022, the borrowing bases are less than the facility limits of $1.575 billion and $1.35 billion, respectively. As of December 31, 2023, available capacity reflects the borrowing base of $1.101 billion and no cash borrowings. As of December 31, 2022, available capacity reflects the borrowing base of $1.208 billion less $400 million in cash borrowings. (d) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 10 to the Financial Statements for detail on our accounts receivable financing. (e) Excludes any additional letters of credit that may be issued under the Secured LOC Facilities. See Note 12 to the Financial Statements for detail on our Secured LOC Facilities. We expect to use cash on hand and borrowings under the Receivables Facility and Repurchase Facility and other liquidity facilities to fund the approximately $3.1 billion cash necessary to close the Energy Harbor acquisition. In addition, we believe that we will have access to sufficient liquidity to fund our other anticipated cash requirements through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted toward the second half of the year. Interest payments on long-term debt are expected to total approximately $744 million in 2024, $1.293 billion in 2025-2026, $955 million in 2027-2028 and $1.052 billion thereafter. See Note 12 to the Financial Statements for details of our long-term debt maturities. 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 $2.615 billion in 2024, $2.192 billion in 2025-2026, $982 million in 2027-2028 and $437 million thereafter. See Note 13 to the Financial Statements for maturities of lease liabilities and Note 14 to the Financial Statements for commitments related to long-term service and maintenance contracts. 69 Table of Contents Capital Expenditures Estimated 2024 capital expenditures and nuclear fuel purchases as of December 31, 2023 total approximately $1.695 billion and include: • $745 million for solar and energy storage development; • $727 million for investments in generation and mining facilities; • $149 million for nuclear fuel purchases; and • $74 million for other growth expenditures. 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 11 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 12 to the Financial Statements for discussion of the Vistra Operations Credit Facilities and the Commodity-Linked Facility. 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, 2023, we received or posted cash, letters of credit and Eligible Assets for commodity hedging and trading activities as follows: • $1.244 billion in cash and Eligible Assets has been posted with counterparties as compared to $3.137 billion posted as of December 31, 2022; • $45 million in cash has been received from counterparties as compared to $39 million received as of December 31, 2022; • $2.408 billion in letters of credit have been posted with counterparties as compared to $2.314 billion posted as of December 31, 2022; and • $143 million in letters of credit have been received from counterparties as compared to $74 million received as of December 31, 2022. 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 do not expect to make federal income tax payments due to Vistra's NOL carryforwards. We expect to make approximately $35 million in state income tax payments offset by $10 million in state tax refunds. For the year ended December 31, 2023, there were no federal income tax payments, $44 million in state income tax payments, $13 million in state income tax refunds and $9 million in TRA payments. Capitalization Our capitalization ratios consisted of 70% and 71% long-term debt (less amounts due currently) and 30% and 29% stockholders' equity at December 31, 2023 and 2022, respectively. Total long-term debt (including amounts due currently) to capitalization was 73% and 71% at December 31, 2023 and 2022, respectively. 70 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 issued revolving letters of credit exceed 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million are taken into account for purposes of determining whether a compliance period is in effect), 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). As of December 31, 2023, we were in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants. See Note 12 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities. 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, at December 31, 2023, Vistra has posted letters of credit in the amount of $91 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 $554 million in the form of letters of credit, $30 million in the form of a surety bond and $3 million of cash at December 31, 2023 (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 greater of $300 million and 17.5% of Consolidated EBITDA 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 $2.5 billion and zero, respectively, as of December 31, 2023. 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. 71 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, 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, 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 Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes and 6.950% Senior Secured Notes, respectively, 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. Guarantees See Note 14 to the Financial Statements for discussion of guarantees. Commitments and Contingencies See Note 14 to the Financial Statements for discussion of commitments and contingencies. Changes in Accounting Standards See Note 1 to the Financial Statements for discussion of changes in accounting standards. 72 Table of Contents