Vistra Corp. 10-K

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the stockholders and the Board of Directors of Vistra Corp. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Vistra Corp. and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in equity, for each of the three years in the period ended December 31, 2024, and the related notes and the schedule listed in the Index at Item 15(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2025, expressed an unqualified opinion on the Company’s internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Fair Value Measurements — Certain Complex Level 3 Derivative Assets and Liabilities — Refer to Notes 1 and 12 to the financial statements Critical Audit Matter Description The Company has derivative assets and liabilities whose fair values are based on complex proprietary models and/or unobservable inputs. These financial instruments can span a broad array of contract types, some of which include especially complex valuations due to unique contract terms and significant judgement by management in estimating prices or volumes, including (1) power purchases and sales that include power and heat rate positions; (2) physical power and natural gas options and swaptions; (3) forward purchase contracts for congestion revenue rights; and (4) retail sales contracts. Under accounting principles generally accepted in the United States of America, these financial instruments are generally classified as Level 3 derivative assets or liabilities. 75 Table of Contents Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of the aforementioned Level 3 derivative assets and liabilities, performing audit procedures to evaluate the reasonableness of the fair value of Level 3 derivative assets and liabilities required a high degree of auditor judgment and an increased extent of effort, including the need to involve our energy commodity fair value specialists who possess significant quantitative and modeling expertise. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the evaluation of the fair value of Level 3 derivative assets and liabilities included the following, among others: • We tested the effectiveness of internal control over derivative asset and liability valuations, including internal control related to appropriate application of illiquid price curves and other significant unobservable valuation inputs. • We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2024, to obtain an understanding of the types of instruments outstanding. • We assessed the consistency by which management has applied illiquid price curves and significant unobservable valuation inputs. • With the assistance of our energy commodity fair value specialists, we developed independent estimates of the fair value of a sample of Level 3 derivative instruments and compared our estimates to the Company's estimates. Energy Harbor Holdings LLC Acquisition — Refer to Note 2 to the financial statements Critical Audit Matter Description The Company completed the acquisition of Energy Harbor Holdings LLC (formerly known as Energy Harbor Corp., “Energy Harbor”) for cash consideration of $3.1 billion and granting a 15% minority interest in certain Vistra businesses with a fair value estimated at $1.5 billion (collectively, the “purchase price consideration”) on March 1, 2024. The Company accounted for the acquisition of Energy Harbor as a business combination. Accordingly, the excess of the purchase price consideration over the identifiable assets acquired and liabilities assumed, was recorded as goodwill. In connection with the business combination, the Company recorded $5.6 billion in property, plant and equipment, which includes the value of the three nuclear power plants. Additionally, a portion of the purchase price consideration also included the fair value of a 15% minority interest in Vistra’s nuclear power plant. The nuclear power plants were valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free cash flow model. The determination of the discounted cash flow model fair value of the nuclear plants included significant judgment and assumptions by management, including future commodity prices, earned production tax credits, anticipated production volumes, future operating costs and capital expenditures, and the discount rate applied to the nuclear plant cash flows. Given the valuation of the nuclear power plants involved complex and subjective estimates of forecasted future growth and financial performance, performing audit procedures to evaluate the reasonableness of the valuation required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists who possess specialized skills and knowledge in modeling the fair value of long term assets. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the evaluation of the fair value of the nuclear power plants included the following, among others: • We tested the effectiveness of internal control over the nuclear power plant valuations, including internal control related to the appropriateness of significant assumptions that are inputs to the fair value calculation and management's review of the valuation model. • We obtained and read the third-party valuation report and evaluated the competency of the third-party specialist engaged by management to perform the valuations. • With the assistance of our fair value specialists, we evaluated the appropriateness of management’s methodology, significant assumptions used to develop the fair value estimate, including the reasonableness of the discount cash flow model itself, the discount rate, present value factor, terminal value, and the internal rate of return, and tested the mathematical accuracy of the calculation. 76 Table of Contents • We evaluated the completeness and accuracy of the underlying data used to develop the forecasts of future cash flows, including assessing the reasonableness of the key assumptions. /s/ Deloitte & Touche LLP Dallas, Texas February 27, 2025 We have served as the Company’s auditor since 2002. 77 Table of Contents VISTRA CORP. CONSOLIDATED STATEMENTS OF OPERATIONS (Millions of Dollars, Except Share Data) Year Ended December 31, 2024 2023 2022 Operating revenues $ 17,224 $ 14,779 $ 13,728 Fuel, purchased power costs, and delivery fees ( 7,285 ) ( 7,557 ) ( 10,401 ) Operating costs ( 2,414 ) ( 1,702 ) ( 1,645 ) Depreciation and amortization ( 1,843 ) ( 1,502 ) ( 1,596 ) Selling, general, and administrative expenses ( 1,601 ) ( 1,308 ) ( 1,189 ) Impairment of long-lived and other assets — ( 49 ) ( 74 ) Operating income (loss) 4,081 2,661 ( 1,177 ) Other income 312 257 117 Other deductions ( 21 ) ( 14 ) ( 4 ) Interest expense and related charges ( 900 ) ( 740 ) ( 368 ) Impacts of Tax Receivable Agreement ( 5 ) ( 164 ) ( 128 ) Net income (loss) before income taxes 3,467 2,000 ( 1,560 ) Income tax (expense) benefit ( 655 ) ( 508 ) 350 Net income (loss) 2,812 1,492 ( 1,210 ) Net (income) loss attributable to noncontrolling interest and redeemable noncontrolling interest ( 153 ) 1 ( 17 ) Net income (loss) attributable to Vistra 2,659 1,493 ( 1,227 ) Cumulative dividends attributable to preferred stock ( 192 ) ( 150 ) ( 150 ) Net income (loss) attributable to Vistra common stock $ 2,467 $ 1,343 $ ( 1,377 ) Weighted average shares of common stock outstanding: Basic 344,788,634 369,771,359 422,447,074 Diluted 352,567,060 375,193,110 422,447,074 Net income (loss) per weighted average share of common stock outstanding: Basic $ 7.16 $ 3.63 $ ( 3.26 ) Diluted $ 7.00 $ 3.58 $ ( 3.26 ) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Millions of Dollars) Year Ended December 31, 2024 2023 2022 Net income (loss) $ 2,812 $ 1,492 $ ( 1,210 ) Other comprehensive income (loss), net of tax effects: Effects related to pension and other retirement benefit obligations (net of tax expense of $ 4 , $ — and $ 7 ) 14 ( 1 ) 23 Total other comprehensive income (loss) 14 ( 1 ) 23 Comprehensive income (loss) 2,826 1,491 ( 1,187 ) Comprehensive (income) loss attributable to noncontrolling interest and redeemable noncontrolling interest ( 153 ) 1 ( 17 ) Comprehensive income (loss) attributable to Vistra $ 2,673 $ 1,492 $ ( 1,204 ) See Notes to the Consolidated Financial Statements 78 Table of Contents VISTRA CORP. CONSOLIDATED BALANCE SHEETS (Millions of Dollars, Except Share Data) December 31, 2024 2023 ASSETS Current assets: Cash and cash equivalents $ 1,188 $ 3,485 Restricted cash 28 40 Trade accounts receivable — net 1,982 1,674 Income taxes receivable 8 6 Inventories 970 740 Commodity and other derivative contractual assets 2,587 3,645 Margin deposits related to commodity contracts 406 1,244 Margin deposits posted under affiliate financing agreement 435 439 Prepaid expense and other current assets 515 364 Total current assets 8,119 11,637 Restricted cash 6 14 Investments 4,512 2,035 Property, plant, and equipment — net 18,173 12,432 Goodwill 2,807 2,583 Identifiable intangible assets — net 2,213 1,864 Commodity and other derivative contractual assets 740 577 Accumulated deferred income taxes 9 1,223 Other noncurrent assets 1,191 601 Total assets $ 37,770 $ 32,966 LIABILITIES AND EQUITY Current liabilities: Accounts receivable financing $ 750 $ — Long-term debt due currently 880 2,286 Forward repurchase obligation due currently 703 — Trade accounts payable 1,510 1,147 Commodity and other derivative contractual liabilities 3,351 5,258 Margin deposits related to commodity contracts 49 45 Accrued taxes other than income 209 203 Accrued interest 193 206 Asset retirement obligations 142 124 Other current liabilities 645 554 Total current liabilities 8,432 9,823 Margin deposits financing with affiliate 435 439 Long-term debt, less amounts due currently 15,418 12,116 Forward repurchase obligation, less amounts due currently 632 — Commodity and other derivative contractual liabilities 1,367 1,688 Accumulated deferred income taxes 697 1 Tax Receivable Agreement obligation 14 164 Asset retirement obligations 3,936 2,414 Other noncurrent liabilities and deferred credits 1,256 999 Total liabilities 32,187 27,644 Commitments and Contingencies See Notes to the Consolidated Financial Statements 79 Table of Contents VISTRA CORP. CONSOLIDATED BALANCE SHEETS (Millions of Dollars, Except Share Data) December 31, 2024 2023 Total equity: Preferred stock ( 100,000,000 shares authorized, $ 1,000 liquidation preference per share, 2,476,066 and 2,476,081 shares outstanding at December 31, 2024 and 2023, respectively) 2,476 2,476 Common stock (par value $ 0.01 per share, 1,800,000,000 shares authorized, 339,754,307 and 351,457,016 shares outstanding at December 31, 2024 and 2023, respectively) 5 5 Treasury stock, at cost ( 208,998,299 and 192,178,156 shares at December 31, 2024 and 2023, respectively) ( 5,912 ) ( 4,662 ) Additional paid-in-capital 9,435 10,095 Accumulated deficit ( 454 ) ( 2,613 ) Accumulated other comprehensive income 20 6 Stockholders' equity 5,570 5,307 Noncontrolling interest in subsidiary 13 15 Total equity 5,583 5,322 Total liabilities and equity $ 37,770 $ 32,966 See Notes to the Consolidated Financial Statements 80 Table of Contents VISTRA CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars) Year Ended December 31, 2024 2023 2022 Cash flows — operating activities: Net income (loss) $ 2,812 $ 1,492 $ ( 1,210 ) Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities: Depreciation and amortization 2,631 1,956 2,047 Deferred income tax expense (benefit), net 607 457 ( 359 ) Gain on sale of land — ( 95 ) ( 8 ) Impairment of long-lived and other assets — 49 74 Unrealized net (gain) loss from mark-to-market valuations of commodities ( 1,155 ) ( 490 ) 2,510 Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps ( 53 ) 36 ( 250 ) Unrealized net gain from nuclear decommissioning trusts ( 116 ) — — Change in asset retirement obligation liability 38 27 13 Asset retirement obligation accretion expense 114 34 34 Impacts of Tax Receivable Agreement 5 164 128 Gain on TRA repurchase and tender offers ( 10 ) ( 29 ) — Bad debt expense 183 164 179 Stock-based compensation 100 77 63 Other, net ( 89 ) 103 ( 71 ) Changes in operating assets and liabilities: Accounts receivable — trade ( 242 ) 214 ( 852 ) Inventories ( 31 ) ( 174 ) 36 Accounts payable — trade 19 ( 350 ) 94 Commodity and other derivative contractual assets and liabilities ( 175 ) 82 ( 228 ) Margin deposits, net 842 1,899 ( 1,874 ) Uplift securitization proceeds receivable from ERCOT — — 544 Accrued interest ( 18 ) 46 16 Accrued taxes ( 1 ) 5 ( 8 ) Accrued employee incentive 8 58 21 Asset retirement obligation settlement ( 88 ) ( 81 ) ( 87 ) Major plant outage deferral ( 91 ) ( 32 ) 20 Other — net assets ( 616 ) 84 ( 17 ) Other — net liabilities ( 111 ) ( 243 ) ( 330 ) Cash provided by operating activities 4,563 5,453 485 Cash flows — investing activities: Capital expenditures, including nuclear fuel purchases and LTSA prepayments ( 2,078 ) ( 1,676 ) ( 1,301 ) Energy Harbor acquisition (net of cash acquired) ( 3,065 ) — — Proceeds from sales of nuclear decommissioning trust fund securities 2,216 601 670 Investments in nuclear decommissioning trust fund securities ( 2,239 ) ( 624 ) ( 693 ) Proceeds from sales of environmental allowances 773 500 1,275 Purchases of environmental allowances ( 1,226 ) ( 1,071 ) ( 1,303 ) Proceeds from sales of property, plant, and equipment, including nuclear fuel 196 115 78 Proceeds from sales of transferable ITCs 150 — — See Notes to the Consolidated Financial Statements 81 Table of Contents VISTRA CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars) Year Ended December 31, 2024 2023 2022 Other, net ( 3 ) 10 35 Cash used in investing activities ( 5,276 ) ( 2,145 ) ( 1,239 ) Cash flows — financing activities: Issuances of long-term debt 3,817 2,498 1,498 Repayments/repurchases of debt ( 2,287 ) ( 33 ) ( 251 ) Net borrowings (repayments) under accounts receivable financing 750 ( 425 ) 425 Borrowings under Revolving Credit Facility 50 100 1,750 Repayments under Revolving Credit Facility ( 50 ) ( 350 ) ( 1,500 ) Borrowings under Commodity-Linked Facility 1,802 — 3,150 Repayments under Commodity-Linked Facility ( 1,802 ) ( 400 ) ( 2,750 ) Debt issuance costs ( 76 ) ( 59 ) ( 31 ) Stock repurchases ( 1,266 ) ( 1,245 ) ( 1,949 ) Dividends paid to common stockholders ( 305 ) ( 313 ) ( 302 ) Dividends paid to preferred stockholders ( 173 ) ( 150 ) ( 151 ) Dividends paid to noncontrolling and redeemable noncontrolling interest holders ( 180 ) — — Payment for acquisition of noncontrolling interest ( 1,748 ) — — TRA Repurchase and tender offer — return of capital ( 122 ) — — Other, net ( 14 ) 83 31 Cash used in financing activities ( 1,604 ) ( 294 ) ( 80 ) Net change in cash, cash equivalents and restricted cash ( 2,317 ) 3,014 ( 834 ) Cash, cash equivalents and restricted cash — beginning balance 3,539 525 1,359 Cash, cash equivalents and restricted cash — ending balance $ 1,222 $ 3,539 $ 525 See Notes to the Consolidated Financial Statements 82 Table of Contents VISTRA CORP. CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Millions of Dollars) Preferred Stock Common Stock Treasury Stock Additional Paid-In Capital Accumulated Deficit Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity Balances at December 31, 2021 $ 2,000 $ 5 $ ( 1,558 ) $ 9,824 $ ( 1,964 ) $ ( 16 ) $ 8,291 $ 1 $ 8,292 Stock repurchases — — ( 1,837 ) — — — ( 1,837 ) — ( 1,837 ) Effects of stock-based incentive compensation plans — — — 103 — — 103 — 103 Net income (loss) — — — — ( 1,227 ) — ( 1,227 ) 17 ( 1,210 ) Dividends declared on common stock — — — — ( 302 ) — ( 302 ) — ( 302 ) Dividends declared on preferred stock — — — — ( 151 ) — ( 151 ) — ( 151 ) Change in accumulated other comprehensive income (loss) — — — — — 23 23 — 23 Other — — — 1 1 — 2 ( 2 ) — Balances at December 31, 2022 $ 2,000 $ 5 $ ( 3,395 ) $ 9,928 $ ( 3,643 ) $ 7 $ 4,902 $ 16 $ 4,918 Series C Preferred Stock issued 476 — — — — — 476 — 476 Stock repurchases — — ( 1,267 ) — — — ( 1,267 ) — ( 1,267 ) Effects of stock-based incentive compensation plans — — — 168 — — 168 — 168 Net income (loss) — — — — 1,493 — 1,493 ( 1 ) 1,492 Dividends declared on common stock — — — — ( 313 ) — ( 313 ) — ( 313 ) Dividends declared on preferred stock — — — — ( 150 ) — ( 150 ) — ( 150 ) Change in accumulated other comprehensive income (loss) — — — — — ( 1 ) ( 1 ) — ( 1 ) Other — — — ( 1 ) — — ( 1 ) — ( 1 ) Balances at December 31, 2023 $ 2,476 $ 5 $ ( 4,662 ) $ 10,095 $ ( 2,613 ) $ 6 $ 5,307 $ 15 $ 5,322 Stock repurchases ( 1,250 ) ( 1,250 ) ( 1,250 ) Effects of stock-based incentive compensation plans — — — 140 — — 140 — 140 Net income — — — — 2,659 — 2,659 102 2,761 Dividends declared on common stock — — — — ( 307 ) — ( 307 ) — ( 307 ) Dividends declared on preferred stock — — — — ( 192 ) — ( 192 ) — ( 192 ) Dividends to noncontrolling interest — — — — — — — ( 15 ) ( 15 ) Change in accumulated other comprehensive income (loss) — — — — — 14 14 — 14 Equity issued in subsidiary to acquire Energy Harbor — — — 747 — — 747 1,560 2,307 See Notes to the Consolidated Financial Statements 83 Table of Contents VISTRA CORP. CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Millions of Dollars) Preferred Stock Common Stock Treasury Stock Additional Paid-In Capital Accumulated Deficit Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity Modification of noncontrolling interest to redeemable noncontrolling interest (a) — — — ( 1,539 ) — — ( 1,539 ) ( 1,659 ) ( 3,198 ) Other — — — ( 8 ) ( 1 ) — ( 9 ) 10 1 Balances at December 31, 2024 $ 2,476 $ 5 $ ( 5,912 ) $ 9,435 $ ( 454 ) $ 20 $ 5,570 $ 13 $ 5,583 ____________ (a) See Note 2 for additional information regarding activity associated with noncontrolling interest. See Notes to the Consolidated Financial Statements 84 Table of Contents VISTRA CORP. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES Description of Business References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary of Terms and Abbreviations for defined terms. Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management, and retail sales of electricity and natural gas to end users. Vistra has five reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. See Note 19 for additional information. Significant Accounting Policies Basis of Presentation The consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2023 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated. Certain prior period amounts have been reclassified to conform with the current year presentation. Use of Estimates Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities as of the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgments related to the potential timing of events, and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. Business Combinations The Company accounts for its business combinations in accordance with ASC 805, Business Combinations , which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value as of the acquisition date. The excess of the purchase price over those fair values is recognized as goodwill (if any). During the measurement period, which may be up to one year from the acquisition date, we may record adjustments to the assets acquired and liabilities assumed in the period in which they are determined. See Note 2 for additional information. Derivative Instruments and Mark-to-Market Accounting We enter derivative instruments, including commodity contracts and interest rate swaps, to manage commodity price and interest rate risks. All our derivatives are accounted for as economic hedges and are recorded at estimated fair value in the consolidated balance sheets with changes in fair value recorded as gains or losses in the earnings of the period in which they occur. No derivative positions are accounted for as cash flow or fair value hedges. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. 85 Table of Contents We report derivative instruments in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities on a gross basis without taking into consideration netting arrangements we have with counterparties. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset derivative assets and liabilities, receivables and payables on settled positions, and collateral to reduce credit exposure between us and the counterparty. Generally, margin deposits that contractually offset derivative instruments are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral. We report commodity hedging and trading results as revenue, fuel expense, or purchased power in the consolidated statements of operations depending on the type of activity. Electricity hedges, financial natural gas hedges, and trading activities are primarily reported as revenue. Physical hedges for coal or fuel oil, along with physical natural gas trades, are primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swap transactions are reported in the consolidated statements of operations in interest expense. See Note 11 for additional information. Revenue Recognition Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed. We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO/RTO, ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response available for system reliability requirements, and certain other electricity sales contracts. See Note 3 for additional information. See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts. Government Assistance The Company qualifies for tax incentives through eligible construction spending and production through the Inflation Reduction Act of 2022 (IRA). These tax incentives generally provide for transferable tax credits upon the applicable qualifying event for the credit type, typically production or in-service date. We account 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 (IAS 20). Transferable PTCs are included in other noncurrent assets in the consolidated balance sheet and included in revenues in the consolidated statements of operations when receipt of the credit is reasonably assured. Transferable investment tax credits (ITCs) are included in other noncurrent assets on the consolidated balance sheet with a corresponding reduction to the cost basis of the Company's plant assets when receipt of the credit is reasonably assured, and reduces depreciation expense over the life of the asset. We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined in ASC 450-20 of U.S. GAAP. See Note 4 for additional information. Major Maintenance Costs Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in the consolidated statements of operations. Defined Benefit Pension Plans and OPEB Plans Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement of such employees from the company. Pension benefits are offered to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. See Note 14 for additional information. 86 Table of Contents Stock-Based Compensation Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation. We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award. Forfeitures are recognized as they occur. See Note 18 for additional information. Sales and Excise Taxes Sales and excise taxes are accounted for as "pass through" items in the consolidated balance sheets with no effect on the consolidated statements of operations ( i.e. , the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction in other current liabilities in the consolidated statements of operations). Franchise and Revenue-Based Taxes Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in the consolidated statements of operations. Income Taxes Deferred income tax assets and liabilities are recorded to reflect, among other things, the temporary timing differences between the book basis and tax basis of assets and liabilities, as required under accounting rules. Investment tax credits that are not transferable are accounted for using the deferral method, which reduces the tax basis of our solar and battery storage facilities. As of both December 31, 2024 and 2023, deferred tax assets related to these credits totaled $ 69 million. We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 5 for additional information. Accounting for Contingencies Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 15 for additional information. Cash and Cash Equivalents For purposes of reporting cash and cash equivalents, temporary cash investments purchased with an original maturity of three months or less are considered cash equivalents. Property, Plant, and Equipment Property, plant, and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed. Significant improvements or additions to our property, plant, and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. Depreciation of our property, plant, and equipment (except for nuclear fuel) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives. See Note 6 for additional information. 87 Table of Contents Nuclear Fuel Nuclear fuel is capitalized and reported as a component of our property, plant, and equipment in the consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs, and delivery fees in the consolidated statements of operations. Impairment of Long-Lived Assets We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss is recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 6 for additional information. Goodwill and Intangible Assets with Indefinite Lives As part of our fresh start reporting and purchase accounting from acquisitions, reorganization value or the purchase consideration is generally allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and liabilities, then any remaining excess reorganization value or purchase consideration is allocated to goodwill. We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. See Note 7 for additional information. Asset Retirement Obligations (ARO) A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. Changes in estimates related to assets that have been retired or for which costs are not recoverable are recorded as operating costs in the consolidated statements of operations. See Note 13 for additional information. Inventories Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects, respectively. Fuel stock and natural gas in storage are reported at the lower of cost (calculated on a weighted average basis) or net realizable value. We expect to recover the value of inventory costs in the normal course of business. See Note 20 for additional information. Nuclear Decommissioning Trust (NDT) Investments and Regulatory Assets or Liability The NRC is responsible for regulating all nuclear power plants in the U.S. This regulatory oversight results in specific accounting considerations for nuclear plant decommissioning. Our NDTs hold funds primarily for the ultimate decommissioning of our nuclear power plants. Each unit has its own NDT and funds from one unit may not be used to fund decommissioning obligations of another unit. Decommissioning costs associated with the Comanche Peak nuclear generation facility in Texas are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the NDT. As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted for as rate regulated operations. Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liability balance that is reflected in the consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits. 88 Table of Contents The NDTs associated with our PJM nuclear facilities have been funded with amounts collected from the previous owners and their respective utility customers. Any shortfall of funds necessary for decommissioning the PJM nuclear facilities, determined for each generating station unit, are required to be funded by us. Investments in the PJM NDTs are carried at fair value and gains and losses are recognized as other income or other deductions in the consolidated statements of operations. NDTs are invested in diversified portfolios of securities generally designed to achieve a return sufficient to fund the future decommissioning work. We retain any funds remaining in the trusts of the PJM nuclear facilities after all decommissioning has been completed. Noncontrolling Interest and Redeemable Noncontrolling Interest in Subsidiary A noncontrolling interest in a consolidated subsidiary represents the portion of the equity in a subsidiary not attributable, directly or indirectly, to the Company. Noncontrolling interests are presented as a separate component of equity in the consolidated balance sheets and the presentation of net income is modified to present earnings attributed to controlling and noncontrolling interests. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. See Note 2 for additional information. Redeemable noncontrolling interests are presented as a component of temporary equity in the mezzanine section of the consolidated balance sheet and the presentation of net income is modified to present earnings attributed to the controlling and redeemable noncontrolling interest. In December 2024, we closed on the repurchase of the noncontrolling interest in Vistra Vision and reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation. See Note 2 and Note 9 for additional information. Treasury Stock Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in the consolidated balance sheets as a reduction to additional paid-in capital. Treasury stock purchases made by third party brokers on our behalf are recorded on a trade date basis when we are contractually obligated to pay the broker for their repurchase costs. See Note 16 for additional information. Leases At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration. Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our secured incremental borrowing rate based on the information available at the lease commencement date to determine the present value of lease payments. Operating leases are included in other noncurrent assets, other current liabilities, and other noncurrrent liabilities and deferred credits on the consolidated balance sheet. Finance leases are included in property, plant, and equipment, other current liabilities and other noncurrent liabilities and deferred credits on the consolidated balance sheet. Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We apply the practical expedient permitted by ASC 842, Leases to not separate lease and non-lease components for a majority of our lease asset classes. Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. 89 Table of Contents Adoption of Accounting Standards in 2024 Improvements to Reportable Segment Disclosures In November 2023, the Financial Accounting Standards Board (FASB) issued ASU No. 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures , to improve the disclosures about reportable segments and add more detailed information about a reportable segment's expenses. The amendments in the ASU require public entities to disclose on an annual and interim basis significant segment expenses that are regularly provided to the chief operating decision maker (CODM) and included within each reported measure of segment profit or loss, other segment items by reportable segment, the title and position of the CODM, and an explanation of how the CODM uses the reported measures of segment profit or loss in assessing segment performance and deciding how to allocate resources. The ASU does not change the definition of a segment, the method for determining segments, the criteria for aggregating operating segments into reportable segments, or the current specifically enumerated segment expenses that are required to be disclosed. The Company adopted the amendments in this ASU for its fiscal year ended December 31, 2024 which resulted in disclosure of significant segment expenses such as segment fuel, purchased power costs, and delivery fees, operating costs, and selling, general, and administrative expenses. The amendment was applied retrospectively to all prior periods presented. See Note 19 for additional information. Recent Accounting Pronouncements Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU No. 2023-09 (ASU 2023-09), Income Taxes (Topic 740): Improvements to Income Tax Disclosures to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. As the amendments apply to income tax disclosures only, the Company does not expect adoption to have a material impact on the consolidated financial statements. Expense Disaggregation Disclosures In November 2024, the FASB issued ASU No. 2024-03 (ASU 2024-03), Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve disclosures by providing additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and interim periods within annual reporting periods beginning after December 15, 2027 and can be applied prospectively or retrospectively. Early adoption is permitted. We are currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures. Recent Developments In January, a fire occurred at our Moss Landing 300 MW battery energy storage facility in the West segment. We are still investigating the cause of the fire and impacts, including insurance claim recoveries, but expect to write off approximately $ 400 million of plant value to depreciation expense in the first quarter of 2025, representing the remaining net book value of the facility. 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. While the gas plant is operational, the other two battery facilities remain offline as we investigate the fire. We will continue to assess if a triggering event has occurred to evaluate impairment for the other complex assets. 90 Table of Contents 2. ACQUISITIONS Energy Harbor Business Combination 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 Energy Harbor Merger was accounted for using the acquisition method in accordance with ASC 805, Business Combinations (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated fair values on the Merger Date. The combined results of operations are reported in the consolidated financial statements beginning as of the Merger Date. The following table summarizes the acquisition date fair value of Energy Harbor associated with the Energy Harbor Merger on the Merger Date: Consideration (in millions) Cash consideration $ 3,100 15 % of the fair value of net assets contributed to Vistra Vision by Vistra (a) 1,496 Total purchase price 4,596 Fair value of noncontrolling interest in Energy Harbor (b) 811 Acquisition date fair value of Energy Harbor $ 5,407 ____________ (a) Valued using a discounted cash flow analysis of the contributed subsidiaries including contributed debt. (b) Represents 15 % of the acquisition date fair value implied from the fair value of consideration transferred. As a result of the Energy Harbor Merger, Vistra maintained an 85 % ownership interest in Vistra Vision and recorded the remaining 15 % equity interest as a noncontrolling interest in the consolidated balance sheets as of the Merger Date. On the Merger Date, we reclassified the carrying value of assets contributed to Vistra Vision of $ 749 million from additional paid-in-capital of Vistra (the controlling interest) to the noncontrolling interest in subsidiary. 91 Table of Contents Provisional fair value measurements were made for acquired assets and liabilities in the first quarter of 2024 and adjustments to those measurements were made in the second, third and fourth quarters of 2024. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The provisional fair values assigned to assets acquired and liabilities assumed are as follows: Fair Value as of March 1, 2024 Measurement Period Adjustments recorded through December 31, 2024 (in millions) Cash and cash equivalents $ 35 $ 5 Trade accounts receivables, inventories, prepaid expenses, and other current assets 544 6 Investments (a) 2,021 — Property, plant, and equipment (b) 5,616 ( 4 ) Identifiable intangible assets (c) 444 16 Commodity and other derivative contractual assets (d) 129 ( 11 ) Other noncurrent assets 61 53 Total identifiable assets acquired 8,850 65 Trade accounts payable and other current liabilities 320 57 Long-term debt, including amounts due currently 413 — Commodity and other derivative contractual liabilities (d) 179 — Accumulated deferred income taxes 1,314 ( 50 ) Asset retirement obligations (e) 1,368 — Identifiable intangible liabilities 55 ( 18 ) Other noncurrent liabilities and deferred credits 18 6 Total identifiable liabilities assumed 3,667 ( 5 ) Identifiable net assets acquired 5,183 70 Goodwill (f) 224 ( 70 ) Net assets acquired $ 5,407 ____________ (a) Investments represent securities held in nuclear decommissioning trusts (NDT) for the purpose of funding the future retirement and decommissioning of the PJM nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC. They are valued using a market approach (Level 1 or Level 2 depending on security). (b) Acquired property, plant, and equipment are valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3). (c) Includes acquired nuclear fuel supply contracts valued based on contractual cash flow projections over approximately five years compared with cash flows based on current market prices with the resulting difference discounted to present value (Level 3). Also includes acquired retail customer relationships which are valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3). (d) Acquired derivatives are valued using the methods described in Note 11 (Level 1, Level 2, or Level 3). Contracts with terms that were not at current market prices are also valued using a discounted cash flow analysis (Level 3). (e) Asset retirement obligations are valued using a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies (Level 3). (f) The excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed is recorded as goodwill. Goodwill represents expected synergies to be generated from combining operations of Energy Harbor with Vistra. None of the Goodwill is deductible for income tax purposes. 92 Table of Contents The following unaudited pro forma financial information for the years ended December 31, 2024 and 2023 assumes that the Energy Harbor Merger occurred on January 1, 2023. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Energy Harbor Merger been completed on January 1, 2023, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here. Year Ended December 31, 2024 2023 (in millions) Revenues $ 17,948 $ 17,148 Net income $ 2,901 $ 1,398 The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Energy Harbor Merger, effects of the Energy Harbor Merger on tax expense (benefit), and other related adjustments. Determining the amounts of revenue and earnings of Energy Harbor since the acquisition date is impractical as operations have been integrated into our commercial platform which is managed at a portfolio level. Acquisition costs incurred in the Energy Harbor Merger totaled $ 25 million and $ 24 million for the year ended December 31, 2024 and 2023, respectively, and are classified as selling, general, and administrative expenses in the consolidated statements of operations. Acquisition of Noncontrolling Interest On September 18, 2024, Vistra Operations and Vistra Vision Holdings I LLC, an indirect wholly owned subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (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. The UPAs contained certain closing conditions outside our control that represent conditional redemption obligations that required us to reflect the transaction as redeemable noncontrolling interest within the mezzanine section of the consolidated balance sheet as of September 30, 2024. The UPAs were amended prior to close to accelerate principal payments to Avenue and certain Nuveen noncontrolling interest holders. The transaction closed on December 31, 2024 (Closing Date), with all closing conditions met. Upon closing, we reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation. See Note 9 for additional information. 93 Table of Contents 3. REVENUE Revenue Disaggregation The following tables disaggregate our revenue by major source: Year Ended December 31, 2024 Retail Texas East (a) West Asset Closure Eliminations / Corporate and Other Consolidated (in millions) Revenue from contracts with customers: Retail energy charge in ERCOT $ 8,064 $ — $ — $ — $ — $ — $ 8,064 Retail energy charge in Northeast/Midwest (a) 3,595 — — — — — 3,595 Wholesale generation revenue from ISO/RTO — 399 1,351 228 — — 1,978 Capacity revenue from ISO/RTO (b) — — 74 — — — 74 Revenue from other wholesale contracts — 422 398 230 — — 1,050 Total revenue from contracts with customers 11,659 821 1,823 458 — — 14,761 Other revenues: Transferable PTC revenues (c) — 292 264 — — — 556 Hedging revenues — realized 1,241 ( 453 ) 31 84 ( 8 ) — 895 Hedging revenue — unrealized ( 168 ) 700 143 329 9 — 1,013 Intangible amortization and other revenues 1 — ( 4 ) — — 2 ( 1 ) Intersegment sales (d) 64 4,034 3,404 6 — ( 7,508 ) — Total other revenues 1,138 4,573 3,838 419 1 ( 7,506 ) 2,463 Total revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ ( 7,506 ) $ 17,224 ____________ (a) Includes ten months of revenue associated with operations acquired in the Energy Harbor Merger. (b) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $ 126 million of capacity sold offset by $ 52 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $ 139 million offset by $ 116 million of capacity sold within the East segment. (c) Represents transferable PTCs generated from qualifying nuclear and solar assets during the period. (d) East segment includes $ 195 million of intersegment unrealized net losses, and Texas and West segments include $ 74 million and $ 4 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment. 94 Table of Contents Year Ended December 31, 2023 Retail Texas East West Asset Closure Eliminations / Corporate and Other Consolidated (in millions) Revenue from contracts with customers: Retail energy charge in ERCOT $ 7,674 $ — $ — $ — $ — $ — $ 7,674 Retail energy charge in Northeast/Midwest 1,642 — — — — — 1,642 Wholesale generation revenue from ISO/RTO — 1,190 1,298 421 — — 2,909 Capacity revenue from ISO/RTO (a) — — 98 — — — 98 Revenue from other wholesale contracts — 505 797 179 — — 1,481 Total revenue from contracts with customers 9,316 1,695 2,193 600 — — 13,804 Other revenues: Transferable PTC revenues (b) — 10 — — — — 10 Hedging revenues — realized 1,063 ( 885 ) 43 67 ( 36 ) — 252 Hedging revenue — unrealized 191 ( 714 ) 958 243 36 — 714 Intangible amortization and other revenues 2 — ( 5 ) — — 2 ( 1 ) Intersegment sales (c) — 3,873 2,701 4 — ( 6,578 ) — Total other revenues 1,256 2,284 3,697 314 — ( 6,576 ) 975 Total revenues $ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ ( 6,576 ) $ 14,779 ____________ (a) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $ 233 million of capacity sold offset by $ 135 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $ 82 million offset by $ 73 million of capacity sold within the East segment. (b) Represents transferable PTCs generated from qualifying solar assets during the period. (c) East segment includes $ 814 million of intersegment unrealized net gains, and Texas and West segments include $ 48 million and $ 6 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment. 95 Table of Contents Year Ended December 31, 2022 Retail Texas East West Asset Closure Eliminations / Corporate and Other Consolidated (in millions) Revenue from contracts with customers: Retail energy charge in ERCOT $ 6,971 $ — $ — $ — $ — $ — $ 6,971 Retail energy charge in Northeast/Midwest 2,139 — — — — — 2,139 Wholesale generation revenue from ISO/RTO — 1,277 1,987 467 562 — 4,293 Capacity revenue from ISO/RTO (a) — — 76 — 27 — 103 Revenue from other wholesale contracts — 696 1,256 151 22 — 2,125 Total revenue from contracts with customers 9,110 1,973 3,319 618 611 — 15,631 Other revenues: Hedging revenues — realized 875 ( 67 ) ( 247 ) 35 ( 333 ) 1 264 Hedging revenue — unrealized ( 532 ) ( 637 ) ( 770 ) ( 326 ) 102 — ( 2,163 ) Intangible amortization and other revenues 2 — ( 6 ) — — — ( 4 ) Intersegment sales (b) — 2,609 2,133 9 4 ( 4,755 ) — Total other revenues 345 1,905 1,110 ( 282 ) ( 227 ) ( 4,754 ) ( 1,903 ) Total revenues $ 9,455 $ 3,878 $ 4,429 $ 336 $ 384 $ ( 4,754 ) $ 13,728 ____________ (a) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $ 361 million of capacity sold offset by $ 285 million of capacity purchased. The Asset Closure segment includes $ 27 million of capacity sold. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $ 212 million offset by $ 167 million of capacity sold within the East segment. (b) Texas and East segments include $ 780 million and $ 45 million, respectively, of intersegment unrealized net losses and West and Asset Closure segments include $ 2 million and $ 4 million respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment. Retail Energy Charges Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 60 days from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed. As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts. 96 Table of Contents Wholesale Generation Revenue from ISOs/RTOs and Revenue from Other Wholesale Contracts Wholesale generation revenue is recognized when volumes are delivered to the ISO/RTO. Other wholesale contracts include other revenue activity with the ISO/RTO, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers, municipalities or other wholesale counterparties. Wholesale revenues are recognized over time using the output method based on kilowatt hours delivered or other applicable performance measurements and cash is settled shortly after invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Wholesale revenues are delivered as a series of distinct services and are accounted for as a single performance obligation. When electricity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in wholesale generation revenues. Capacity Revenue From ISO/RTO We offer generation capacity into competitive ISO/RTO auctions in exchange for revenue from awarded capacity offers. Capacity ensures installed generation and demand response is available to satisfy system integrity and reliability requirements. Capacity revenues are recognized when the performance obligation is satisfied ratably over time as our power generation facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO/RTO against generation facilities if the facility is not available during the capacity period and are recorded as a reduction to revenue. When capacity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in capacity revenue from ISO/RTO. Other Revenues Other revenues, as included in the tables of disaggregated revenue above, represent amounts not accounted for under ASC 606, Revenue from Contracts with Customers and are comprised of the following: • Transferable production tax credit revenues accounted for as income-related grants by analogy to IAS 20 (see Note 4 for additional information). • Intangible amortization of acquired intangible liabilities related to retail and wholesale contracts (see Note 7 for additional information). • Hedging revenue from electricity and natural gas derivative contracts accounted for under ASC 815, Derivatives and Hedging, including the impact of realized and unrealized gains or losses on those contracts (see Note 11 for additional information). • Intersegment sales are presented by segment and eliminated in consolidation. Contract and Other Customer Acquisition Costs We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of December 31, 2024 and 2023 was $ 114 million and $ 97 million, respectively. The amortization related to these costs during the years ended December 31, 2024, 2023, and 2022 totaled $ 97 million, $ 88 million, and $ 83 million respectively, recorded as SG&A expenses, and $ 6 million, $ 6 million, and $ 6 million, respectively, recorded as a reduction to operating revenues in the consolidated statements of operations. Practical Expedients The majority of our revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient. We have elected to not disclose the value of unsatisfied performance obligations for contracts with variable consideration for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar customer contracts with similar performance obligations. Sales taxes are not included in revenue. 97 Table of Contents Performance Obligations As of December 31, 2024, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers for which the total consideration is fixed and determinable at contract execution. Capacity revenues are recognized as the performance obligations to make capacity available to the related ISOs/RTOs or counterparties are met. 2025 2026 2027 2028 2029 2030 and Thereafter Total (in millions) Remaining performance obligations $ 1,123 $ 825 $ 289 $ 122 $ 62 $ 548 $ 2,969 Trade Accounts Receivable December 31, 2024 December 31, 2023 (in millions) Wholesale and retail trade accounts receivable $ 2,061 $ 1,735 Allowance for credit losses ( 79 ) ( 61 ) Trade accounts receivable — net $ 1,982 $ 1,674 Trade accounts receivable from contracts with customers — net $ 1,514 $ 1,239 Other trade accounts receivable — net 468 435 Total trade accounts receivable — net $ 1,982 $ 1,674 Gross trade accounts receivable as of December 31, 2024 and December 31, 2023 include unbilled retail revenues of $ 802 million and $ 614 million, respectively. Allowance for Credit Losses on Accounts Receivable Year Ended December 31, 2024 2023 2022 (in millions) Allowance for credit losses on accounts receivable at beginning of period $ 61 $ 65 $ 45 Increase for bad debt expense 183 164 179 Decrease for account write-offs ( 165 ) ( 168 ) ( 159 ) Allowance for credit losses on accounts receivable at end of period $ 79 $ 61 $ 65 4. GOVERNMENT ASSISTANCE 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 section 45U nuclear PTC provides a federal tax credit of up to $15 per MWh, subject to phase out as power prices increase above $25 per MWh, to existing nuclear facilities from 2024 through 2032 subject to an annual inflation adjustment. 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 . 98 Table of Contents Transferable PTCs In the year ended December 31, 2024, we recognized transferable nuclear PTC revenues of $ 545 million and transferable solar PTC revenues of $ 11 million. Our nuclear PTC revenues are an estimate based on gross receipts generated from qualifying nuclear production in 2024 and reflect our determination that we will meet the prevailing wage requirements necessary to earn the five times multiplier at all of our nuclear units. Our computation of gross receipts includes settled spot energy revenues and capacity revenues at each nuclear unit, and excludes any hedges. Treasury regulations are expected to further define the scope of the legislation in many important respects over the next year, including interpretive guidance on the definition of gross receipts for the nuclear PTC. 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. Transferable ITCs In June 2023, our 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III) in California commenced commercial operations. As a result of Moss Landing Phase III meeting requirements to be placed in service in June 2023, we recognized $ 154 million of transferable ITCs associated with the project in other noncurrent assets in the consolidated balance sheet. In September 2024, we recognized an additional $ 2 million of transferable ITCs associated with the project and reclassified the $ 156 million of credits to other current assets. In December 2024, our Baldwin 68 MW solar / 2 MW battery ESS and Coffeen 44 MW solar / 2 MW battery ESS facilities in Illinois met requirements to be placed in service. As a result, we recognized $ 57 million and $ 45 million of transferable ITCs associated with the projects, respectively, in other noncurrent assets in the consolidated balance sheet. Sales of Transferable PTCs and ITCs In October 2024, we sold $ 156 million of transferable ITCs and $ 10 million of transferable solar PTCs generated in 2023. Vistra received cash consideration from the sale in October 2024. In January 2025, we sold $ 200 million of transferable nuclear PTCs we recognized from qualifying 2024 nuclear production. Cash consideration from the sale will be received in installments through July 2025 with an initial payment received in January 2025. 5. INCOME TAXES Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra serves as the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group. Income Tax Expense (Benefit) The components of our income tax expense (benefit) are as follows: Year Ended December 31, 2024 2023 2022 (in millions) Current: U.S. Federal $ 2 $ ( 1 ) $ 2 State 46 52 7 Total current 48 51 9 Deferred: U.S. Federal 561 421 ( 304 ) State 46 36 ( 55 ) Total deferred 607 457 ( 359 ) Total $ 655 $ 508 $ ( 350 ) 99 Table of Contents Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded: Year Ended December 31, 2024 2023 2022 (in millions) Income (loss) before income taxes $ 3,467 $ 2,000 $ ( 1,560 ) U.S. federal statutory rate 21 % 21 % 21 % Income taxes at the U.S. federal statutory rate 728 420 ( 328 ) State tax, net of federal benefit 80 86 ( 19 ) Nondeductible TRA accretion 2 41 18 Transferable PTC revenues ( 115 ) ( 2 ) — Equity awards ( 53 ) ( 3 ) ( 3 ) Valuation allowance ( 2 ) ( 20 ) ( 8 ) Release of Uncertain Tax Positions — ( 35 ) — Other 15 21 ( 10 ) Income tax expense (benefit) $ 655 $ 508 $ ( 350 ) Effective tax rate 18.9 % 25.4 % 22.4 % Deferred Income Tax Balances Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2024 and 2023 are as follows: December 31, 2024 2023 (in millions) Noncurrent Deferred Income Tax Assets Tax credit carryforwards $ 86 $ 84 Loss carryforwards 949 1,081 Identifiable intangible assets 340 380 Long-term debt 225 173 Employee benefit obligations 133 117 Commodity contracts and interest rate swaps 383 664 Other 36 33 Total deferred tax assets $ 2,152 $ 2,532 Noncurrent Deferred Income Tax Liabilities Property, plant, and equipment 2,765 1,264 Total deferred tax liabilities 2,765 1,264 Valuation allowance 75 46 Net Deferred Income Tax Asset (Liability) $ ( 688 ) $ 1,222 As of December 31, 2024, we had total net deferred tax liabilities of approximately $ 688 million that were substantially comprised of book and tax basis differences related to our generation and mining property, plant, and equipment, partially offset by federal and state net operating loss (NOL) carryforwards. Our net deferred tax liabilities were significantly impacted by the Energy Harbor Merger. For the years ended December 31, 2024 and 2023, we recognized tax benefits of $ 2 million and $ 20 million primarily related to the release of the federal valuation allowance on charitable contributions and state valuation allowances, respectively. As of December 31, 2024, we assessed the need for a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. We have identified positive evidence in the form of cumulative income on an unadjusted basis over the preceding 12 quarters. We evaluated historical earnings, performed scheduling of the reversal of temporary differences, and considered other positive and negative evidence. In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by future taxable income, and thus no valuation allowance was required. A valuation allowance of approximately $ 30 million was recorded as part of Energy Harbor purchase accounting on state NOL carryforwards. 100 Table of Contents As of December 31, 2024, we had $ 3.2 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2031. The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax liabilities of $ 4 million and zero at December 31, 2024 and 2023, respectively. IRA In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. 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. See Notes 1 and 4 for additional information. Final Section 163(j) Regulations The final Section 163(j) regulations, which limits qualified deductions for business interest expense, were issued in July 2020 and provided a critical correction to the proposed regulations regarding the computation of adjusted taxable income. As of January 1, 2022, certain provisions in the final Section 163(j) regulations have sunset, including the add-back of depreciation and amortization to adjusted taxable income. As a result, under the law as currently enacted, Vistra's deductible business interest expense was significantly limited for the 2024 tax year and will continue to be so limited under current law going forward. Vistra remains active in legislative monitoring and advocacy efforts to support a legislative solution to reinstate and make permanent the add-back of depreciation and amortization to adjusted taxable income. Liability for Uncertain Tax Positions Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable. We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were immaterial for the years ended December 31, 2024, 2023, and 2022. The following table summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets for the years ended December 31, 2024, 2023, and 2022. Year Ended December 31, 2024 2023 2022 (in millions) Balance at beginning of period, excluding interest and penalties $ — $ 36 $ 38 Additions based on tax positions related to prior years 4 — — Reductions based on tax positions related to prior years — — ( 1 ) Reductions related to the lapse of the tax statute of limitations — ( 35 ) — Settlements with taxing authorities — ( 1 ) ( 1 ) Balance at end of period, excluding interest and penalties $ 4 $ — $ 36 Vistra and its subsidiaries file income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject to examinations by the IRS and other taxing authorities. In February 2021, Vistra was notified that the IRS had opened a federal income tax audit for tax years 2018 and 2019. The federal income tax audit was closed in June 2023 with immaterial changes. Uncertain tax positions totaled $ 4 million and zero as of December 31, 2024 and 2023, respectively. Of the amounts recorded as unrecognized tax benefits, an insignificant portion would impact our effective tax rate if recognized. Tax Matters Agreement On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties. 101 Table of Contents Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp. We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions. Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off. Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d) we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off. 6. PROPERTY, PLANT, AND EQUIPMENT Our property, plant, and equipment consist of our power generation assets, related mining assets, land, information system hardware, capitalized corporate office lease space and other leasehold improvements. The estimated remaining useful lives of our property, plant, and equipment ranges from 1 to 29 years. Land is not depreciated. December 31, 2024 2023 (in millions) Power generation and structures $ 22,783 $ 17,297 Land 603 572 Office and other equipment 160 159 Total 23,546 18,028 Less accumulated depreciation ( 8,020 ) ( 6,657 ) Net of accumulated depreciation 15,526 11,371 Finance lease right-of-use assets (net of accumulated amortization) 153 160 Nuclear fuel (net of accumulated amortization of $ 409 million and $ 120 million) 1,434 379 Construction work in progress 1,060 522 Property, plant, and equipment — net $ 18,173 $ 12,432 Depreciation expenses totaled $ 1.670 billion, $ 1.344 billion, and $ 1.388 billion for the years ended December 31, 2024, 2023, and 2022, respectively. 102 Table of Contents Retirement of Generation Facilities The following are all of our facilities that have either been retired, or that have announced retirement dates. Operation results for plants with defined retirement dates are included in our Asset Closure segment at the beginning of the calendar year the retirement is expected to occur. Facility Location ISO/RTO Fuel Type Net Generation Capacity (MW) Announced Retirement Date (a) Segment Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2027 East Coleto Creek Goliad, TX ERCOT Coal 650 By the end of 2027 (b) Texas Kincaid Kincaid, IL PJM Coal 1,108 By the end of 2027 East Miami Fort North Bend, OH PJM Coal 1,020 By the end of 2027 East Newton Newton, IL MISO Coal 615 By the end of 2027 East Edwards Bartonville, IL MISO Coal 585 Retired January 1, 2023 Asset Closure Joppa Joppa, IL MISO Coal 802 Retired September 1, 2022 Asset Closure Joppa Joppa, IL MISO Natural Gas 221 Retired September 1, 2022 Asset Closure Zimmer Moscow, OH PJM Coal 1,300 Retired June 1, 2022 Asset Closure Total 7,486 ____________ (a) Generation facilities may retire earlier than expected dates disclosed if economic or other conditions dictate. (b) Following the retirement of Coleto Creek as a coal-fueled plant, the Company intends to repower it as a gas-fueled plant. Impairment of Long-Lived Assets In the first quarter of 2023, we recognized an impairment loss of $ 49 million related to our Kincaid generation facility in Illinois as a result of a significant decrease in the projected operating margins of the facility, primarily driven by a decrease in projected power prices. The impairment is reported in our East segment and includes write-downs of property, plant, and equipment of $ 45 million, write-downs of inventory of $ 2 million, and write-downs of operating lease right-of-use assets of $ 2 million. In the fourth quarter of 2022, we recognized an impairment loss of $ 74 million related to our Miami Fort generation facility in Ohio as a result of a significant decrease in the projected operating margins of the facility, reflecting an increase in projected coal costs along with a decrease in projected power prices. The impairment is reported in our East segment and includes write-downs of property, plant, and equipment of $ 71 million and write-downs of inventory of $ 3 million. In determining the fair value of the impaired asset groups in 2023 and 2022, we utilized the income approach described in ASC 820, Fair Value Measurement . 7. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES Goodwill As of December 31, 2024 and 2023, the carrying value of goodwill totaled $ 2.807 billion and $ 2.583 billion, respectively. Retail Segment Texas Segment Retail Reporting Unit (a) Texas Generation Reporting Unit Total Goodwill (in millions) Balance at December 31, 2023 $ 2,461 $ 122 $ 2,583 Goodwill recorded in connection with the Energy Harbor Merger (b) 224 Balance at December 31 2024 $ 2,461 $ 122 $ 2,807 ____________ (a) Goodwill of $ 1.944 billion is deductible for tax purposes over 15 years on a straight-line basis. (b) Allocation of goodwill attributable to the Energy Harbor acquisition to reporting units is pending completion of purchase accounting measurement period. 103 Table of Contents Goodwill is required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist. We have selected October 1 as our annual goodwill test date. On the most recent goodwill testing date, we applied qualitative factors 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, 2024. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, interest rates, market capitalization, and changes in reporting unit book value. Identifiable Intangible Assets and Liabilities Identifiable intangible assets are comprised of the following: December 31, 2024 December 31, 2023 Identifiable Intangible Asset Gross Carrying Amount Accumulated Amortization Net Gross Carrying Amount Accumulated Amortization Net (in millions) Retail customer relationship $ 2,173 $ 1,977 $ 196 $ 2,088 $ 1,866 $ 222 Software and other technology-related assets 601 293 308 536 315 221 Retail and wholesale contracts 503 353 150 233 217 16 Long-term service agreements 18 5 13 18 5 13 Other identifiable intangible assets (a) 218 13 205 62 11 51 Total identifiable intangible assets subject to amortization $ 3,513 $ 2,641 872 $ 2,937 $ 2,414 523 Retail trade names (not subject to amortization) 1,341 1,341 Total identifiable intangible assets $ 2,213 $ 1,864 ____________ (a) Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates). Identifiable intangible liabilities are comprised of the following: Year Ended December 31, Identifiable Intangible Liability 2024 2023 (in millions) Long-term service agreements $ 108 $ 122 Wholesale power and fuel purchase contracts 47 9 Total identifiable intangible liabilities $ 155 $ 131 104 Table of Contents Amortization of finite-lived identifiable intangible assets and liabilities (including the classification in the consolidated statements of operations) consisted of: Identifiable Intangible Assets/Liabilities Consolidated Statements of Operations Remaining useful lives of identifiable intangible assets at December 31, 2024 (weighted average in years) Year Ended December 31, 2024 2023 2022 (in millions) Retail customer relationship Depreciation and amortization 2 $ 111 $ 98 $ 137 Software and other technology-related assets Depreciation and amortization 3 60 58 69 Retail and wholesale contracts Operating revenues/Fuel, purchased power costs, and delivery fees 3 ( 12 ) 8 7 Other identifiable intangible assets Fuel, purchased power costs, and delivery fees/Depreciation and amortization 4 414 357 391 Total intangible asset expense, net $ 573 $ 521 $ 604 Amounts recorded in depreciation and amortization totaled $ 173 million, $ 158 million, and $ 208 million for the years ended December 31, 2024, 2023, and 2022, respectively. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs, and delivery fees in the consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs. The following is a description of the separately identifiable intangible assets recorded in fresh start reporting and in connection with purchase accounting from acquisitions. • Retail customer relationship — Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life. • Retail and wholesale contracts — These intangible assets and liabilities represent the value of various acquired retail and wholesale contracts and fuel and transportation purchase contracts. The contracts were identified as either assets or liabilities based on the respective fair values utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The intangible assets or liabilities are amortized in relation to the economic terms of the related contracts. • LTSA — Our acquired LTSA intangibles represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements and are amortized based on the expected usage of the service agreements over the contract terms. The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant, and equipment. • Retail trade names — Our retail trade name intangible assets represent the fair value of our retail brands, including the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power, and U.S. Gas & Electric, and were determined to be indefinite-lived assets not subject to amortization. These intangible assets are evaluated for impairment at least annually in accordance with accounting guidance related to other indefinite-lived intangible assets. We have selected October 1 as our test date. Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest rates. On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2024. 105 Table of Contents Estimated Amortization of Identifiable Intangible Assets As of December 31, 2024, the estimated aggregate amortization expense of identifiable intangible assets, excluding environmental allowances, for each of the next five fiscal years is as shown below. Year Estimated Amortization Expense (in millions) 2025 $ 231 2026 $ 167 2027 $ 72 2028 $ 51 2029 $ 34 8. 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 (the Trust) 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 can 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 has 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. 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. Vistra Operations pays a facility fee (Facility Fee) to the Trust payable on each May 17 and November 17, commencing on November 17, 2023, to and including May 17, 2028 (each, a Distribution Date), and on certain other dates as provided in the Facility Agreement. The Facility Fee is generally calculated at a rate of 3.3608 % per annum, applied to the maximum amount of 7.233 % Senior Secured Notes that Vistra Operations could issue and sell to the Trust under the Facility Agreement as of the close of business on the business day immediately preceding the applicable Distribution Date. As of December 31, 2024 and 2023, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $ 435 million and $ 439 million, respectively, and is reported in the consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate. 106 Table of Contents 9. DEBT, CREDIT FACILITIES, AND FINANCINGS Amounts in the table below represent the categories of debt obligations incurred by the Company. December 31, 2024 2023 (in millions) Long-term debt, including amounts due currently: Project-level debt $ 1,064 $ — Vistra Operations debt 15,405 14,517 Long-term debt before unamortized premiums, discounts, and issuance costs 16,469 14,517 Unamortized premiums, discounts, and issuance costs ( 171 ) ( 115 ) Long-term debt including debt due currently $ 16,298 $ 14,402 Accounts receivable financing $ 750 $ — Forward repurchase obligation $ 1,335 $ — 107 Table of Contents Long-Term Debt Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company. December 31, 2024 2023 (in millions) Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 $ 2,475 $ 2,500 BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 367 — Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 697 — Vistra Operations Senior Secured Notes: 4.875 % Senior Secured Notes, due May 13, 2024 — 400 3.550 % Senior Secured Notes, due July 15, 2024 — 1,500 5.125 % Senior Secured Notes, due May 13, 2025 744 1,100 5.050 % Senior Secured Notes, due December 30, 2026 500 — 3.700 % Senior Secured Notes, due January 30, 2027 800 800 4.300 % Senior Secured Notes, due July 15, 2029 800 800 6.950 % Senior Secured Notes, due October 15, 2033 1,050 1,050 6.000 % Senior Secured Notes, due April 15, 2034 500 — 5.700 % Senior Secured Notes, due December 30, 2034 750 — Total Vistra Operations Senior Secured Notes 5,144 5,650 Energy Harbor Revenue Bonds: 3.375 % Revenue Bond, due August 1, 2029 100 — 4.750 % Revenue Bond, due June 1, 2033 and July 1, 2033 285 — 3.750 % Revenue Bond, due October 1, 2047 46 — Total Energy Harbor Revenue Bonds 431 — Vistra Operations Senior Unsecured Notes: 5.500 % Senior Unsecured Notes, due September 1, 2026 1,000 1,000 5.625 % Senior Unsecured Notes, due February 15, 2027 1,300 1,300 5.000 % Senior Unsecured Notes, due July 31, 2027 1,300 1,300 4.375 % Senior Unsecured Notes, due May 15, 2029 1,250 1,250 7.750 % Senior Unsecured Notes, due October 15, 2031 1,450 1,450 6.875 % Senior Unsecured Notes, due April 15, 2032 1,000 — Total Vistra Operations Senior Unsecured Notes 7,300 6,300 Other: Equipment Financing Agreements 55 67 Total other long-term debt 55 67 Unamortized debt premiums, discounts, and issuance costs ( 171 ) ( 115 ) Total long-term debt including amounts due currently 16,298 14,402 Less amounts due currently ( 880 ) ( 2,286 ) Total long-term debt less amounts due currently $ 15,418 $ 12,116 108 Table of Contents Long-Term Debt Maturities Long-term debt maturities at December 31, 2024 are as follows: December 31, 2024 (in millions) 2025 $ 885 2026 1,792 2027 3,427 2028 27 2029 2,177 Thereafter 8,161 Unamortized premiums, discounts, and debt issuance costs ( 171 ) Total long-term debt, including amounts due currently $ 16,298 Credit Facilities Our credit facilities and related available capacity at December 31, 2024 are presented below. December 31, 2024 Credit Facilities Maturity Date Facility Limit Cash Borrowings (Long-Term Debt, Including Amounts Due Currently) Letters of Credit Outstanding Available Capacity (in millions) Vistra Operations debt: Revolving Credit Facility October 11, 2029 $ 3,440 $ — $ 1,278 $ 2,162 Term Loan B-3 Facility December 20, 2030 2,475 2,475 — — Total Vistra Operations Credit Facilities $ 5,915 $ 2,475 $ 1,278 $ 2,162 Vistra Operations Commodity-Linked Facility October 1, 2025 1,750 — — 771 Total Vistra Operations debt $ 7,665 $ 2,475 $ 1,278 $ 2,933 Project-level debt: Tax Credit Bridge Loan November 1, 2025 106 106 — — Tax Credit Bridge Loan December 3, 2026 261 261 — — BCOP Credit Facility 367 367 — — Vistra Zero Term Loan B Facility (a) April 30, 2031 697 697 — — Total project-level debt $ 1,064 $ 1,064 $ — $ — Total credit facilities $ 8,729 $ 3,539 $ 1,278 $ 2,933 ____________ (a) Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries. 109 Table of Contents Vistra Operations Credit Facilities Vistra maintains credit facilities with certain financial institutions and, as of December 31, 2024, has aggregate commitments of up to $ 5.915 billion in senior secured, first-lien revolving credit commitments and outstanding term loans (Vistra Operations Credit Facilities). The Vistra Operations Credit Facilities consist of (i) revolving credit commitments of up to $ 3.440 billion, including aggregate revolving letter of credit commitments of up to $ 3.440 billion (Revolving Credit Facility), and (ii) term loans of $ 2.475 billion (Term Loan B-3 Facility). These amounts reflect the following transactions and amendments completed in 2024: Amendment Date Key Changes December 2024 Lowered fixed spread on Term Loan B-3 Facility borrowings from 2.00 % to 1.75 % October 2024 Increased Revolving Credit Facility commitments from $ 3.175 billion to $ 3.440 billion Extended the maturity date of the Revolving Credit Facility to October 11, 2029 Revolving Credit Facility — The Revolving Credit Facility is used for general corporate purposes. Under the Vistra Operations Credit Agreement, the interest on borrowings under the Revolving Credit Facility is paid based on (i) the forward-looking term rate based on SOFR (Term SOFR) plus a spread that will range from 1.25 % to 2.00 % and (ii) the fee on any undrawn amounts with respect to the Revolving Credit Facility ranges from 17.5 basis points to 35.0 basis points. Interest periods for Term SOFR borrowings are for a one-, three-, or six-month periods with interest paid in arrears. Letters of credit issued under the Revolving Credit Facility bear interest that ranges from 1.25 % to 2.00 % and are paid quarterly in arrears. Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of December 31, 2024, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 1.725 % and 27.0 basis points, respectively, and the applicable interest rate margin for the letters of credit issued under the Revolving Credit Facility was 1.725 %. Term Loan B-3 Facility — The Term Loan B-3 Facility is used for general corporate purposes and bears interest based on the applicable Term SOFR, plus a fixed spread of 2.00 % through December 9, 2024 and 1.75 % thereafter, and the weighted average interest rates before taking into consideration interest rate swaps (see Note 11) on outstanding borrowings of $ 2.475 billion was 6.11 % as of December 31, 2024. Interest periods for Term SOFR loans are for a one-, three-, or six-month periods with interest paid in arrears. Cash borrowings under the Term Loan B-3 Facility are subject to required scheduled quarterly payments of $ 6.25 million. Amounts paid cannot be reborrowed. Other Information — Obligations under the Vistra Operations Credit Facilities are secured by liens covering substantially all of Vistra Operations' (and certain of its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities. The Vistra Operations Credit Agreement includes certain collateral suspension provisions that would take effect upon Vistra Operations achieving unsecured investment grade ratings from two ratings agencies and there being no Term Loans (under and as defined in the Vistra Operations Credit Agreement) then outstanding (or the holders thereof agreeing to release such security interests). Such collateral suspension provisions would continue to be in effect unless and until Vistra Operations no longer holds unsecured investment grade ratings from at least two ratings agencies, at which point collateral reversion provisions would take effect (subject to a 60 -day grace period). The Vistra Operations Credit Facilities also permit certain hedging agreements and cash management agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements and cash management agreements meet certain criteria set forth in the Vistra Operations Credit Facilities. The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agent under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Facilities. The Vistra Operations Credit Agreement also includes a springing financial covenant with respect to the Revolving Credit Facility that, when applicable, would require compliance with a consolidated first lien net leverage ratio. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein. 110 Table of Contents The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest, or fees when due, material breaches of representations and warranties, breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the existence of material unpaid (or unstayed) judgments against Vistra Operations and certain of its subsidiaries. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders. The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2024, Vistra Operations can distribute approximately $ 8.2 billion to Parent under the Vistra Operations Credit Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $ 1.705 billion, $ 1.625 billion, and $ 1.775 billion during the years ended December 31, 2024, 2023, and 2022, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to pay any taxes or general operating or corporate overhead expenses arising out of Parent's ownership or operation of Vistra Operations. As of December 31, 2024, all of the restricted net assets of Vistra Operations may be distributed to Parent. Vistra Operations Commodity-Linked Revolving Credit Facility As of December 31, 2024, Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) totaled $ 1.75 billion of aggregate available commitments. We have the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility to $ 3.0 billion. As of December 31, 2024, the borrowing base of $ 771 million is lower than the facility limit which represents the aggregate commitments of $ 1.75 billion. These amounts reflect the following amendment completed in 2024: Amendment Date Key Changes October 2024 Increased the aggregate available commitments to $ 1.75 billion Extended the maturity date to October 1, 2025 Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero. Vistra Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce outstanding borrowings to be less than or equal to the borrowing base. Vistra Operations intends to use any borrowings provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capital and general corporate purposes. Interest on the Commodity-Linked Facility bears interest (i) based on either the Term SOFR or a daily simple SOFR rate, (ii) a spread that ranges from 1.25 % to 2.00 %, and (iii) sustainability pricing adjustments based on certain sustainability-linked targets and thresholds. Interest periods for Term SOFR borrowings are for a one-, three-, or six-month periods with interest paid in arrears. The interest period for a daily simple SOFR is for a one-week period with interest paid in arrears. The fee on any undrawn amounts with respect to the Commodity-Linked Facility ranges from 17.5 basis points to 35.0 basis points. As of December 31, 2024, the applicable interest rate margins for borrowings outstanding under the Commodity-Linked Facility was 1.725 % and the fee on any undrawn amounts with respect to the Commodity-Linked Facility was 27.0 basis points. Interest and fees on the Commodity-Linked Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. BCOP Project-level Credit Facilities In December 2024, BCOP and its subsidiaries entered into the BCOP Credit Agreement to fund the development of the Baldwin and Coffeen solar generation and battery ESS facilities and the Oak Hill and Pulaski solar generation facilities in Illinois and Texas. The BCOP Credit Agreement provides for (i) tax credit bridge loans of $ 367 million for the Oak Hill and Pulaski projects (Tax Credit Bridge Loans) and (ii) construction/term loan commitments of $ 528 million and debt service reserve letter of credit facility commitments of $ 29 million for all four facilities. 111 Table of Contents At December 31, 2024, the Tax Credit Bridge Loans for Oak Hill and Pulaski totaled $ 106 million and $ 261 million, respectively, and mature in November 2025 and December 2026, respectively, subject to the terms of the BCOP Credit Agreement. The weighted average interest rate on outstanding borrowings was 5.984 % at December 31, 2024. Repayment of the Tax Credit Bridge Loans are guaranteed by Vistra as the beneficiary of the underlying investment tax credits to be generated by the projects. At December 31, 2024, there were no construction/term loan borrowings outstanding or debt service reserve letters of credit issued. Interest is paid on the Tax Credit Bridge Loan in arrears based on the applicable Term SOFR rate elected in the borrowing notice plus a fixed spread of 1.625 % per annum. Interest on the construction/term loans will be paid in arrears based on the applicable Term SOFR rate elected in the borrowing notice plus fixed spreads of 1.875 % per annum for construction loans and 2.000 % per annum for term loans. Fees on the debt service reserve letter of credit loans will be paid in arrears at 2.000 % per annum. Commitment fees on the undrawn loan commitments and unissued letter of credit commitments will pay quarterly in arrears at a fixed percentage of the loan's fixed spread. Vistra Zero Project-level Credit Agreement In March 2024, Vistra Zero Operations entered into the Vistra Zero Credit Agreement. The Vistra Zero Credit Agreement provides for a senior secured term loan (Term Loan B Facility) of up to $ 700 million, which Vistra Zero Operations borrowed in its entirety in March 2024. Net proceeds of $ 690 million were used (i) to pay issuance costs and (ii) for working capital and general corporate purposes. Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries. These amounts reflect the following amendment completed in 2024: Amendment Date Key Changes December 2024 Lowered the fixed spread interest applicable to the Term Loan B Facility from 2.75 % to 2.00 % Removed required scheduled quarterly payment requirements Interest on the Term Loan B Facility is based on Term SOFR plus 2.75 % per year through December 16, 2024. The December 2024 amendment lowered the fixed spread on this instrument to 2.00 % thereafter. Interest periods for Term SOFR loans are for a one-, three-, or six-month periods with interest paid in arrears. The weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings of $ 697 million was 6.36 % as of December 31, 2024. The Vistra Zero Credit Agreement contains customary covenants and warranties which are generally consistent in scope with the Vistra Operations Credit Agreement, except that there is no financial maintenance covenant in the Vistra Zero Credit Agreement. Letter of Credit Facilities Vistra Operations Secured Letter of Credit Facilities Between August 2020 and July 2024, we entered into uncommitted standby letter of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities). The Secured LOC Facilities may be renewed annually and are used for general corporate purposes. As of December 31, 2024, $ 1.157 billion of letters of credit were outstanding under the Secured LOC Facilities. Vistra Operations Unsecured Alternative Letter of Credit Facilities In March 2024, we entered into unsecured alternative letter of credit facilities (Alternative LOC Facilities) to be used for general corporate purposes. In May 2024, the Alternative LOC Facilities were amended to increase the commitment cap to a total of $ 500 million. As of December 31, 2024, the total capacity was $ 500 million and $ 500 million of letters of credit were outstanding under the Alternative LOC Facilities. The commitments under the Alternative LOC Facilities terminate in December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities. 112 Table of Contents Vistra Operations Senior Secured Notes Vistra Operations issues and sells its senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Secured Notes). The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the Senior Secured Notes provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a first-priority security interest in the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities and contains certain covenants and restrictions consistent with the Vistra Operations Credit Facilities. In December 2024, Vistra Operations issued $ 1.25 billion aggregate principal amount of senior secured notes, consisting of $ 500 million aggregate principal amount of 5.050 % senior secured notes due 2026 ( 5.050 % Senior Secured Notes) and $ 750 million aggregate principal amount of 5.700 % senior secured notes due 2034 ( 5.700 % Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in arrears on June 30 and December 30 beginning June 30, 2025. Net proceeds totaling approximately $ 1.240 billion, together with cash on hand, will be used for (i) general corporate purposes, including to refinance outstanding indebtedness (including 2025 debt maturities), (ii) to fund the opportunistic early payout of the purchase price installment payments scheduled to be paid in 2025 and 2026 to Avenue for the acquisition of the noncontrolling interest in Vistra Vision and (iii) to pay fees and expenses related to the offering. In May 2024 and July 2024, the 4.875 % senior secured notes due May 2024 and 3.550 % senior secured notes due July 2024, respectively, were repaid at maturity. In April 2024, Vistra Operations issued $ 500 million aggregate principal amount of 6.000 % senior secured notes due 2034 ( 6.000 % Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024. Net proceeds totaling approximately $ 495 million, together with proceeds from the April 2024 issuance of 6.875 % Senior Unsecured Notes discussed below and cash on hand, were to be used for general corporate purposes, including to refinance outstanding indebtedness (the senior secured debt maturities in May 2024 and July 2024). Energy Harbor Revenue Bonds Various governmental entities in Ohio and Pennsylvania have issued multiple tranches of revenue bonds for the benefit of Energy Harbor Generation LLC (EHG) or Energy Harbor Nuclear Generation LLC (EHNG); (collectively, the EH entities), in an aggregate principal amount of $ 431 million. The relevant EH entity is obligated to provide contractual payments to the applicable issuer of the revenue bonds to service the principal and interest on the revenue bonds, the payment of which is indirectly secured by all or substantially all of the assets of the EH entities under various mortgage bonds issued by the EH entities. In the event of a default by the EH entities of their contractual obligation to pay principal and interest in respect of the revenue bonds, the trustee of the revenue bonds would be able to call the mortgage bonds due and, if unpaid, foreclose on the assets securing the mortgage bonds. The obligations of the EH entities in respect of the revenue bonds and related mortgage bonds are guaranteed on an unsecured basis by Energy Harbor and Vistra. Vistra Operations Senior Unsecured Notes Vistra Operations issues and sells its senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Unsecured Notes). The indentures (as may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) governing the Senior Unsecured Notes provide for the full and unconditional guarantee by the Guarantor Subsidiaries. The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets. In April 2024, Vistra Operations issued $ 1.0 billion aggregate principal amount of 6.875 % senior unsecured notes due 2032 ( 6.875 % Senior Unsecured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024. Net proceeds totaling approximately $ 990 million, together with proceeds from the April 2024 issuance of 6.000 % Senior Secured Notes discussed above and cash on hand, were to be used for general corporate purposes, including to refinance outstanding indebtedness (including the senior secured debt maturities in May 2024 and July 2024). 113 Table of Contents Other Debt Activity Senior Secured Notes Tender Offer In January 2024, Vistra Operations used the net proceeds from (i) the December 2023 issuances of the 6.950 % senior secured notes due 2033 and 7.750 % senior unsecured notes due 2031 and (ii) cash on hand, to fund a cash tender offer (Senior Secured Notes Tender Offer) to purchase for cash $ 759 million aggregate principal amount of certain notes, 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. We recorded an extinguishment gain of $ 6 million on the transaction in the first quarter of 2024. Accounts Receivable Financing Accounts Receivable Securitization Program TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). In April 2024, the Receivables Facility was amended to increase the purchase limit from $ 750 million to $ 1.0 billion and to add Energy Harbor LLC, a direct, wholly owned subsidiary of Energy Harbor, as an Originator. The Receivables Facility was renewed and amended in July 2024, extending the term of the Receivables Facility to July 2025. In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limit described above to fund its acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the performance of the obligations of the Originators and TXU Energy, as the servicer, under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings in the consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in the consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable. As of December 31, 2024, outstanding borrowings under the Receivables Facility totaled $ 750 million and were supported by $ 1.334 billion of RecCo gross receivables. As of December 31, 2023, there were no outstanding borrowings under the Receivables Facility. Repurchase Facility TXU Energy and the other Originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2024, the Repurchase Facility was renewed until July 2025 while maintaining the facility size of $ 125 million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Repo Transaction). Each Repo Transaction is expected to have a term of one month , unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default. 114 Table of Contents TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the Receivables Facility. There were no outstanding borrowings under the Repurchase Facility as of both December 31, 2024 and December 31, 2023. Forward Repurchase Obligation In accordance with the amended UPAs, on December 31, 2024, Vistra closed the acquisition of the Vistra Vision minority interests from Avenue and Nuveen. Vistra paid Avenue for the purchase of their minority interest in Vistra Vision in full upon closing and paid Nuveen an initial payment at closing, with the remaining payments to Nuveen to be paid in multiple installments through December 31, 2026. Vistra Vision Holdings' remaining future payments to Nuveen are guaranteed by Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes. Payments remaining due to Nuveen are as follows: December 31, 2024 (in millions) 2025 $ 781 2026 669 Thereafter — Total scheduled payments under the UPAs $ 1,450 A roll-forward of the noncontrolling interest redemption obligation is as follows (in millions): Redeemable noncontrolling interest at September 30, 2024 $ 3,198 Income attributable to redeemable noncontrolling interest (a) 51 Dividends to redeemable noncontrolling interest holders ( 165 ) Redeemable noncontrolling interest balance at Closing Date (b) 3,084 Principal payment on Closing Date ( 1,749 ) Forward Repurchase Obligation at December 31, 2024 (c) $ 1,335 ____________ (a) Represents accretion attributable to fixed price redemption obligation. (b) Reclassified to a financing obligation. (c) Fair value of the remaining payment obligations to Nuveen discounted at 6 %. Interest Expense and Related Charges Year Ended December 31, 2024 2023 2022 (in millions) Interest expense $ 936 $ 654 $ 591 Unrealized mark-to-market net (gains) losses on interest rate swaps ( 53 ) 36 ( 250 ) Amortization of debt issuance costs, discounts, and premiums 34 26 28 Facility Fee expense 15 8 — Debt extinguishment gain ( 6 ) ( 3 ) ( 1 ) Capitalized interest ( 77 ) ( 37 ) ( 29 ) Other 51 56 29 Total interest expense and related charges $ 900 $ 740 $ 368 The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 5.23 %, 5.69 %, and 4.30 % as of December 31, 2024, 2023, and 2022, respectively. 115 Table of Contents 10. LEASES Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease terms for 1 to 42 years. Our leases include options to renew up to 17 years. Certain leases also contain options to terminate the lease. Lease Cost The following table presents costs related to lease activities: Year Ended December 31, 2024 2023 2022 (in millions) Operating lease cost $ 17 $ 12 $ 9 Finance lease: Finance lease right-of-use asset amortization 8 10 9 Interest on lease liabilities 11 11 12 Total finance lease cost 19 21 21 Variable lease cost (a) 29 37 22 Short-term lease cost 56 44 47 Total lease cost $ 121 $ 114 $ 99 ____________ (a) Represents coal stockpile management services, common area maintenance services, and rail car payments based on the number of rail cars used. Balance Sheet Information The following table presents lease related balance sheet information: December 31, 2024 2023 (in millions) Lease assets: Operating lease right-of-use assets (reported in other noncurrent assets in the consolidated balance sheets) $ 106 $ 50 Finance lease right-of-use assets, net of accumulated amortization (reported in property, plant, and equipment in the consolidated balance sheets) 153 $ 160 Total lease right-of-use assets $ 259 $ 210 Current lease liabilities (reported in other current liabilities in the consolidated balance sheets): Operating lease liabilities $ 13 $ 7 Finance lease liabilities 9 9 Total current lease liabilities 22 16 Noncurrent lease liabilities (reported in other noncurrent liabilities and deferred credits in the consolidated balance sheets): Operating lease liabilities 98 48 Finance lease liabilities 218 227 Total noncurrent lease liabilities 316 275 Total lease liabilities $ 338 $ 291 116 Table of Contents Supplemental Cash Flow Information The following table presents lease related cash flows and other information: Year Ended December 31, 2024 2023 2022 (in millions) Non-cash disclosure upon commencement of new lease: Right-of-use assets obtained in exchange for new operating lease liabilities 68 3 19 Right-of-use assets obtained in exchange for new finance lease liabilities — — 6 Non-cash disclosure upon modification of existing lease: Modification of operating lease right-of-use assets 1 7 — Modification of finance lease right-of-use assets — ( 1 ) 4 Weighted Average Remaining Lease Term The following table presents weighted average remaining lease term information: December 31, 2024 2023 Weighted average remaining lease term: Operating lease 23.8 years 20.1 years Finance lease 23.7 years 24.0 years Weighted average discount rate: Operating lease 7.85 % 6.49 % Finance lease 4.82 % 4.81 % Maturity of Lease Liabilities The following table presents maturity of lease liabilities: Operating Lease Finance Lease Total Lease (in millions) 2025 $ 19 $ 19 $ 38 2026 13 14 27 2027 14 13 27 2028 10 13 23 2029 8 13 21 Thereafter 222 331 553 Total lease payments 286 403 689 Less: Imputed interest ( 175 ) ( 176 ) ( 351 ) Present value of lease liabilities $ 111 $ 227 $ 338 11. DERIVATIVES We utilize derivative instruments, such as options, swaps, futures, and forward contracts to manage our exposure to commodity price and interest rate volatility. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, fuel oil and natural gas producers, local distribution companies, and energy marketing companies. 117 Table of Contents Commodity Derivatives We utilize financial natural gas and financial and physical electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets. Financial transmission rights and congestion revenue rights are derivative instruments we utilize to hedge electricity price differences between settlement points within regions. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in operating revenues. We utilize physical natural gas, coal, emissions, and renewable energy certificate derivatives primarily to hedge future purchased power costs of our retail operations or fuel costs of our generation assets. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in fuel, purchased power costs, and delivery fees. Our retail segment procures power from our generation segments to serve future load obligations. In locations and periods where our load service activities do not naturally offset existing generation portfolio risks, remaining commodity price exposure is managed through portfolio hedging activities. Interest Rate Swaps Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in interest expense and related charges. As of December 31, 2024, Vistra has entered into the following interest rate swaps: Notional Amount Expiration Date Rate Range (c) (in millions, except percentages) Swapped to fixed (a) $ 3,000 July 2026 4.64 % - 4.72 % Swapped to variable (a) $ 700 July 2026 3.19 % - 3.24 % Swapped to fixed (b) $ 2,300 December 2030 4.95 % - 5.51 % ____________ (a) The $ 700 million of pay variable rate and receive fixed rate swaps match the terms of a portion of the $ 3.0 billion pay fixed rate and receive variable rate swaps. These matched swaps will settle over time and effectively offset the hedged position. These offsetting swaps expiring in July 2026 hedge our exposure on $ 2.3 billion of variable rate debt through July 2026. (b) Effective from July 2026 through December 2030. (c) The rate ranges reflect the fixed leg of each swap at a Term SOFR rate plus an interest margin of 1.75 %. In November 2024, Vistra entered into $ 675 million notional amount of interest rate swaps effective July 31, 2026 and expiring on December 31, 2030. These swaps, along with $ 1.625 billion notional amount of interest rate swaps with similar terms entered into in 2023, will hedge our exposure on $ 2.3 billion of floating rate debt from August 2026 through December 2030. 118 Table of Contents Effect of Derivative Instruments in the Consolidated Balance Sheets We maintain standardized master netting agreements with certain counterparties that allow for the right to offset accounts payable, accounts receivable and cash collateral paid in order to reduce credit exposure. The following tables reconcile our gross derivative assets and liabilities as reported in the consolidated balance sheets to the net value on a contract basis, after taking into consideration netting arrangements with counterparties and cash collateral recorded. December 31, 2024 Derivative Contract Assets Derivative Contract Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total (in millions) Current assets $ 2,551 $ 34 $ 2 $ — $ 2,587 Noncurrent assets 677 62 1 — 740 Current liabilities — — ( 3,333 ) ( 18 ) ( 3,351 ) Noncurrent liabilities ( 2 ) — ( 1,356 ) ( 9 ) ( 1,367 ) Net assets (liabilities) $ 3,226 $ 96 $ ( 4,686 ) $ ( 27 ) $ ( 1,391 ) Offsetting instruments (a) $ ( 2,532 ) $ ( 28 ) $ 2,532 $ 28 — Financial collateral (received) pledged (b) $ ( 50 ) $ — $ 233 $ — 183 Net amounts $ 644 $ 68 $ ( 1,921 ) $ 1 $ ( 1,208 ) December 31, 2023 Derivative Contract Assets Derivative Contract Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total (in millions) Current assets $ 3,585 $ 53 $ 7 $ — $ 3,645 Noncurrent assets 565 11 1 — 577 Current liabilities ( 1 ) — ( 5,233 ) ( 24 ) ( 5,258 ) Noncurrent liabilities ( 5 ) — ( 1,659 ) ( 24 ) ( 1,688 ) Net assets (liabilities) $ 4,144 $ 64 $ ( 6,884 ) $ ( 48 ) $ ( 2,724 ) Offsetting instruments (a) $ ( 3,519 ) $ ( 28 ) $ 3,519 $ 28 — Financial collateral (received) pledged (b) $ ( 26 ) $ — $ 970 $ — 944 Net amounts $ 599 $ 36 $ ( 2,395 ) $ ( 20 ) $ ( 1,780 ) ____________ (a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. (b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements. 119 Table of Contents Effect of Derivative Instruments in the Consolidated Statements of Operations The following table summarizes the location and amount of unrealized gains and losses from our derivative instruments recorded in the consolidated statements of operations for the periods presented. Year Ended December 31, Derivative (consolidated statements of operations presentation) 2024 2023 2022 (in millions) Reversals of previously recognized unrealized (gain) loss on derivative instruments: Commodity contracts unrealized (gain) loss in operating revenues (a) $ 1,140 $ 1,472 $ 1,940 Commodity contracts unrealized (gain) loss in fuel and purchased power expense (a) 73 171 ( 722 ) Interest rate swaps unrealized (gain) loss in interest expense and related charges ( 41 ) ( 78 ) 16 Total reversals of previously recognized unrealized (gain) loss on derivative instruments $ 1,172 $ 1,565 $ 1,234 Unrealized net gains (losses) from changes in fair value on derivative instruments: Commodity contracts unrealized gain (loss) in operating revenues $ ( 127 ) $ ( 758 ) $ ( 4,103 ) Commodity contracts unrealized gain (loss) in fuel and purchased power expense 69 ( 395 ) 375 Interest rate swaps unrealized gain (loss) in interest expense and related charges 94 42 234 Total unrealized net gains (losses) from changes in fair value on derivative instruments $ 36 $ ( 1,111 ) $ ( 3,494 ) Net gain (loss) on derivative instruments $ 1,208 $ 454 $ ( 2,260 ) ____________ (a) Excludes the realized effects of changes in fair value in the month the position settled, amounts related to positions entered into and settled in the same month, and physical retail and wholesale contracts accounted for as derivatives which did not financially settle but realized at the contract's notional and price. The realized effects of these items are included in operating revenues and fuel and purchased power expense. Derivative Volumes The following table presents the gross notional amounts of derivative volumes by commodity, excluding our NPNS derivatives that are not recorded at fair value: December 31, 2024 December 31, 2023 Derivative type Notional Volume Unit of Measure Natural gas 4,568 5,335 Million MMBtu Electricity 796,982 800,001 GWh Financial transmission rights / Congestion revenue rights 248,742 250,895 GWh Coal 27 35 Million U.S. tons Fuel oil 2 3 Million gallons Emissions 28 24 Million U.S. tons Renewable energy certificates 31 29 Million certificates Interest rate swaps – variable/fixed $ 5,300 $ 5,225 Million U.S. dollars Interest rate swaps - fixed/variable $ 700 $ 1,300 Million U.S. dollars 120 Table of Contents Credit Risk-Related Contingent Features of Derivatives Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements may require the posting of additional collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized: December 31, 2024 2023 (in millions) Fair value of derivative contract liabilities (a) $ ( 1,587 ) $ ( 1,890 ) Offsetting fair value under netting arrangements (b) 724 692 Cash collateral and letters of credit 471 854 Liquidity exposure $ ( 392 ) $ ( 344 ) ____________ (a) Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses). (b) Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements. Concentrations of Credit Risk Related to Derivatives We have concentrations of credit risk with the counterparties to our derivative contracts. As of December 31, 2024, total credit risk exposure to all counterparties related to derivative contracts totaled $ 3.772 billion (including associated accounts receivable). The net exposure to those counterparties totaled $ 776 million as of December 31, 2024 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure from any single counterparty totaling $ 262 million. As of December 31, 2024, the credit risk exposure to the banking and financial sector represented 75 % of the total credit risk exposure and 26 % of the net exposure. This concentration of credit risk increases the risk that a default by any of our counterparties could have a material effect on our financial condition, results of operations and liquidity. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation procedures including, but not limited to, (i) requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our counterparties that allow for netting of positive and negative exposures, and (iii) that detail credit enhancements (such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits) are required in the event of a material downgrade in their credit rating. 12. FAIR VALUE MEASUREMENTS Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own market assumptions. We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy as defined by GAAP: • Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. 121 Table of Contents • Level 2 valuations use over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals. • Level 3 valuations use unobservable inputs for the asset or liability, typically reflecting our estimate of assumptions that market participants would use in pricing the asset or liability. The fair value is therefore determined using model-based techniques, including discounted cash flow models. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement. Assets and Liabilities Measured at Fair Value on a Recurring Basis Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below: December 31, 2024 December 31, 2023 Level 1 Level 2 Level 3 (a) Reclass (a) Total Level 1 Level 2 Level 3 (a) Reclass (a) Total (in millions) Assets: Commodity contracts (b) $ 1,923 $ 462 $ 841 $ 5 $ 3,231 $ 2,886 $ 628 $ 630 $ 14 $ 4,158 Interest rate swaps (b) — 96 — — 96 — 64 — — 64 NDTs – equity securities (c)(d) 1,560 — — — 1,560 638 — — — 638 NDTs – debt securities (c)(e) 83 1,976 — — 2,059 — 734 — — 734 Sub-total $ 3,566 $ 2,534 $ 841 $ 5 6,946 $ 3,524 $ 1,426 $ 630 $ 14 5,594 Assets measured at net asset value (f): NDTs – equity securities (c)(d)(f) 821 579 Total assets $ 7,767 $ 6,173 Liabilities: Commodity contracts (b) $ 2,118 $ 975 $ 1,593 $ 5 $ 4,691 $ 3,815 $ 1,395 $ 1,674 $ 14 $ 6,898 Interest rate swaps (b) — 27 — — 27 — 48 — — 48 Total liabilities $ 2,118 $ 1,002 $ 1,593 $ 5 $ 4,718 $ 3,815 $ 1,443 $ 1,674 $ 14 $ 6,946 ____________ (a) Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability position. This reclassification represents the adjustment needed to reconcile to the gross amounts presented in the consolidated balance sheets. (b) See Note 11 for additional information. (c) NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in Investments in the consolidated balance sheets. There were no significant concentrations of credit risk from an individual counterparty or groups of counterparties in our NDT portfolio as of December 31, 2024. (d) The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments. (e) The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt securities are weighted with government and investment grade corporate bonds. Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 3.99 % and 3.19 % as of December 31, 2024 and 2023, respectively, and an average maturity of 7 years and 11 years as of December 31, 2024 and 2023, respectively. NDT debt securities held as of December 31, 2024 mature as follows: $ 1.045 billion in one to five years, $ 599 million in five to 10 years and $ 415 million after 10 years. 122 Table of Contents (f) Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair values and therefore are not classified in the fair value hierarchy. This amount is presented to permit reconciliation of this table to the amounts presented in the consolidated balance sheets. The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of December 31, 2024 and 2023: December 31, 2024 Fair Value Contract Type (a) Assets Liabilities Total, Net Valuation Technique Significant Unobservable Input Range (b) Average (b) (in millions) Electricity purchases and sales $ 606 $ ( 1,399 ) $ ( 793 ) Income Approach Hourly price curve shape (c) $ — to $ 95 $ 48 MWh Illiquid delivery periods for hub power prices (d) $ 25 to $ 140 $ 83 MWh Market Heat Rates (d) $ 30 to $ 150 $ 90 MWh Options 6 ( 139 ) ( 133 ) Option Pricing Model Natural gas to power correlation (e) 10 % to 100 % 55 % Power and natural gas volatility (e) 5 % to 710 % 358 % Financial transmission rights/Congestion revenue rights 190 ( 25 ) 165 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 35 ) to $ 20 $ ( 8 ) MWh Natural gas 29 ( 30 ) ( 1 ) Income Approach Natural gas basis (h) $ — to $ 10 $ 5 MMBtu Illiquid delivery periods (i) $ — to $ 5 $ 2 MMBtu Other (j) 10 — 10 Total $ 841 $ ( 1,593 ) $ ( 752 ) 123 Table of Contents December 31, 2023 Fair Value Contract Type (a) Assets Liabilities Total, Net Valuation Technique Significant Unobservable Input Range (b) Average (b) (in millions) Electricity purchases and sales $ 449 $ ( 1,273 ) $ ( 824 ) Income Approach Hourly price curve shape (c) $ — to $ 85 $ 44 MWh Illiquid delivery periods for hub power prices and Heat Rates (d) $ 30 to $ 110 $ 71 MWh Options 1 ( 237 ) ( 236 ) Option Pricing Model Natural gas to power correlation (e) 10 % to 100 % 55 % Power and natural gas volatility (e) 10 % to 870 % 441 % Financial transmission rights/Congestion revenue rights 157 ( 34 ) 123 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 85 ) to $ 25 $ ( 30 ) MWh Natural gas 9 ( 112 ) ( 103 ) Income Approach Natural gas basis (h) $ — to $ 15 $ 6 MMBtu Illiquid delivery periods (i) $ — to $ 5 $ 4 MMBtu Other (j) 14 ( 18 ) ( 4 ) Total $ 630 $ ( 1,674 ) $ ( 1,044 ) ____________ (a) Electricity purchase and sales contracts include (i) power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts. (b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount. (c) Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices. (d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability. (e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM. (f) While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid. (g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones. (h) Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices. (i) Primarily based on the historical forward natural gas fixed prices. (j) Other includes contracts for coal and environmental allowances. 124 Table of Contents The following table presents the changes in fair value of the Level 3 assets and liabilities: Year Ended December 31, 2024 2023 2022 (in millions) Net liability balance at beginning of period $ ( 1,044 ) $ ( 1,219 ) $ ( 360 ) Total unrealized valuation gains (losses) ( 175 ) ( 765 ) ( 1,382 ) Purchases, issuances and settlements (a): Purchases 266 222 185 Issuances ( 26 ) ( 30 ) ( 62 ) Settlements 137 136 345 Transfers into Level 3 (b) ( 15 ) ( 48 ) ( 30 ) Transfers out of Level 3 (b) 118 660 85 Net liabilities assumed in connection with the Energy Harbor Merger ( 13 ) — — Net change 292 175 ( 859 ) Net liability balance at end of period $ ( 752 ) $ ( 1,044 ) $ ( 1,219 ) Unrealized valuation (losses) relating to instruments held at end of period $ ( 416 ) $ ( 676 ) $ ( 977 ) ____________ (a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs. (b) Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the year ended December 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and natural gas derivatives where forward pricing inputs have become observable. For the year ended December 31, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable. For the year ended December 31, 2022, transfers into Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power, natural gas, and coal derivatives where forward pricing inputs have become observable. Assets and Liabilities Recorded on a Non-Recurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventories, assets acquired and liabilities assumed in business combinations, goodwill and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale. The Energy Harbor Merger was accounted for under the acquisition method which requires all assets acquired and liabilities assumed in the acquisition be recorded at fair value at the acquisition date. See Note 2 for additional information. Fair Value of Debt December 31, 2024 December 31, 2023 Instrument Fair Value Hierarchy Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,435 $ 2,478 $ 2,456 $ 2,500 BCOP Credit Facilities Tax Credit Bridge Loan Level 3 344 367 — — Vistra Zero Term Loan B Facility Level 2 685 697 — — Vistra Operations Senior Notes Level 2 12,366 12,428 11,881 11,752 Energy Harbor Revenue Bonds Level 2 414 431 — — Equipment Financing Agreements Level 3 54 53 65 62 Forward Repurchase Obligation Level 3 1,335 1,335 — — 125 Table of Contents We determine fair value in accordance with accounting standards. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg. 13. ASSET RETIREMENT OBLIGATIONS Our asset retirement obligations (ARO) primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs. AROs are based on legal obligations associated with enacted law, regulatory, or contractual retirement requirements for which decommissioning timing and cost estimates are reasonably estimable. The following table summarizes the changes to our current and noncurrent ARO liabilities for the years ended December 31, 2024 and 2023: Nuclear Plant Decommissioning Land Reclamation, Coal Ash and Other Total (in millions) Liability at December 31, 2022 $ 1,688 $ 749 $ 2,437 Additions: Accretion (a) 54 34 88 Adjustment for change in estimates (b) — 94 94 Reductions: Payments — ( 81 ) ( 81 ) Liability at December 31, 2023 1,742 796 2,538 Additions: Accretion (a) 130 40 170 Adjustment for change in estimates (b) — 90 90 Adjustment for obligations assumed through acquisitions 1,368 — 1,368 Reductions: Payments — ( 88 ) ( 88 ) Liability at December 31, 2024 3,240 838 4,078 Less amounts due currently — ( 142 ) ( 142 ) Noncurrent liability at December 31, 2024 $ 3,240 $ 696 $ 3,936 ____________ (a) For the year ended December 31, 2024, nuclear plant decommissioning accretion includes $ 74 million of accretion expense recognized in operating costs in the consolidated statements of operations and $ 56 million reflected as a change in regulatory liability in the consolidated balance sheets. For the year ended December 31, 2023, nuclear plant decommissioning accretion reflected as a change in regulatory liability in the consolidated balance sheets. (b) Includes non-cash additions to asset retirement costs included in property, plant, and equipment of $ 52 million and $ 67 million for the years ended December 31, 2024 and 2023, respectively. For the next five years, Vistra is projected to spend approximately $ 546 million (on a nominal basis) to achieve its mining reclamation and other coal ash remediation objectives. Nuclear Decommissioning AROs AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and the facilities acquired from Energy Harbor which include the Beaver Valley, Perry and Davis-Besse plants in PJM (the PJM nuclear facilities). To estimate our nuclear decommissioning obligations we use a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. 126 Table of Contents As of December 31, 2024, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $ 1.797 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $ 2.249 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $ 452 million recorded to the consolidated balance sheets in other noncurrent liabilities and deferred credits since any excess funds in the NDT after decommissioning our Comanche Peak plant would be refunded to Oncor. The carrying value of our ARO for our PJM nuclear facilities was recorded at fair value on the Merger Date. ARO accretion expense attributable to the PJM nuclear facilities is reflected in operating costs in the consolidated statements of operations. ARO estimates for the PJM nuclear facilities will be evaluated on an individual unit basis at least every five years unless triggering events warrant a more frequent review. Any changes in ARO estimates are recorded as an increase or decrease in ARO liability along with a corresponding change to asset retirement cost asset within property, plant, and equipment in the consolidated balance sheets; however, if the ARO estimate decreases by more than the remaining ARO asset, the balance of the change is recorded as a reduction to operating costs in the consolidated statement of operations. 14. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries. Oncor is a participant in the Retirement Plan. Effective January 1, 2018, Vistra entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra. As Vistra accounts for its interests in the Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension benefit information presented below. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations. Since 2012, the Retirement Plan has been closed to new participants and the only participants who remain in the Retirement Plan are employees who were active prior to 2012, including retired collective bargaining unit employees. Accordingly, ongoing expenses associated with the Retirement plan are immaterial, including expenses associated with pensions plans acquired from Dynegy and Energy Harbor. Vistra and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service. Pension and OPEB Costs The following table summarizes the total benefit costs of our pension and OPEB plans for the years ended December 31, 2024, 2023, and 2022. The individual components of benefit costs, including service cost, interest cost, expected return on assets and the net amortization of unrecognized amounts from accumulated other comprehensive income were immaterial. Year Ended December 31, 2024 2023 2022 (in millions) Pension costs $ 9 $ 9 $ 2 OPEB costs 5 5 4 Total benefit costs recognized as expense $ 14 $ 14 $ 6 127 Table of Contents Market-Related Value of Assets Held in Pension Benefit Trusts We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25 % of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year. Detailed Information Regarding Pension Plans and OPEB Benefits The following information is based on a December 31, 2024, 2023, and 2022 measurement dates: Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2022 2024 2023 2022 Assumptions Used to Determine Benefit Obligations at Period End: Discount rate 5.63 % 4.97 % 5.16 % 5.62 % 4.98 % 5.18 % Expected rate of compensation increase (Vistra Plan) 3.50 % 3.64 % 3.79 % Expected rate of compensation increase (Dynegy Plan) 4.46 % Interest crediting rate for cash balance plans 3.75 % 3.50 % 3.00 % Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2024 2023 (in millions, except percentages) Change in Pension and Postretirement Benefit Obligations: Projected benefit obligation at beginning of period $ 425 $ 449 $ 108 $ 110 Acquisitions 23 — — — Service cost 2 3 1 1 Interest cost 21 21 5 5 Participant contributions — — 3 3 Plan amendments — 1 — — Actuarial (gain) loss ( 24 ) 10 ( 7 ) 1 Benefits paid ( 38 ) ( 59 ) ( 11 ) ( 12 ) Projected benefit obligation at end of year $ 409 $ 425 $ 99 $ 108 Accumulated benefit obligation at end of year $ 408 $ 422 $ — $ — Change in Plan Assets: Fair value of assets at beginning of period $ 285 $ 320 $ 12 $ 29 Acquisitions 18 — — — Employer contributions 19 — 8 9 Participant contributions — — 2 3 Actual gain on assets 1 24 1 2 Transfers — — ( 2 ) ( 19 ) Benefits paid ( 38 ) ( 59 ) ( 11 ) ( 12 ) Fair value of assets at end of year $ 285 $ 285 $ 10 $ 12 Funded Status: Projected benefit obligation $ ( 409 ) $ ( 425 ) $ ( 99 ) $ ( 108 ) Fair value of assets 285 285 10 12 Funded status at end of year $ ( 124 ) $ ( 140 ) $ ( 89 ) $ ( 96 ) 128 Table of Contents Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2024 2023 Amounts Recognized in the Balance Sheet Consist of: Investments $ 1 $ — $ 2 $ 3 Other current liabilities — — ( 8 ) ( 9 ) Other noncurrent liabilities ( 125 ) ( 140 ) ( 83 ) ( 90 ) Net liability recognized $ ( 124 ) $ ( 140 ) $ ( 89 ) $ ( 96 ) Amounts Recognized in Accumulated Other Comprehensive Income Consist of: Net actuarial (gain) loss $ ( 5 ) $ 4 $ ( 22 ) $ ( 15 ) Prior services cost — 3 1 1 Net actuarial (gain) loss and prior service cost $ ( 5 ) $ 7 $ ( 21 ) $ ( 14 ) Fair Value Measurement of Pension and OPEB Plan Assets Retirement Plan As of December 31, 2024 and 2023, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following: December 31, 2024 2023 (in millions) Asset Category: Cash commingled trusts $ 6 $ 4 Equity securities: Global equities 86 82 Fixed income securities: Corporate bonds (a) 79 82 Government bonds 42 54 Other (b) 28 18 Real estate 27 28 Hedge funds 17 17 Total assets measured at net asset value $ 285 $ 285 ___________ (a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's. (b) Consists primarily of high-yield bonds, emerging market debt, bank loans, securitized bonds and private investment grade fixed income. OPEB Plans As of December 31, 2024 and 2023, the Vistra OPEB plan assets measured at fair value totaled $ 10 million and $ 12 million, respectively. At December 31, 2024 and 2023, assets consisted of $ 7 million and $ 9 million, respectively, of comingled funds valued at net asset value and $ 3 million and $ 3 million, respectively, of municipal bond and cash equivalent mutual funds classified as Level 1. 129 Table of Contents Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO) in Excess of Plan Assets The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets. December 31, 2024 2023 (in millions) Pension Plans with PBO and ABO in Excess of Plan Assets: Projected benefit obligations $ 409 $ 425 Accumulated benefit obligation $ 408 $ 422 Plan assets $ 285 $ 285 Retirement Plan Investment Strategy and Asset Allocations Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities, and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets. Real estate, hedge funds, and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential. The target asset allocation ranges of pension plan investments by asset category are as follows: Retirement Plan Target Allocation Ranges Asset Category: Vistra Plan Dynegy Plan Energy Harbor Plan Fixed income securities 50 % - 70 % 40 % - 50 % 45 % - 55 % Global equity securities 20 % - 28 % 28 % - 38 % 30 % - 38 % Real estate 6 % - 10 % 7 % - 15 % 5 % - 10 % Credit strategies 2 % - 6 % 4 % - 8 % 4 % - 8 % Hedge funds 2 % - 6 % 4 % - 8 % 1 % - 5 % Retirement Plan Expected Long-Term Rate of Return on Assets Assumption The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management. Retirement Plan Expected Long-Term Rate of Return Asset Class: Vistra Plan Dynegy Plan Energy Harbor Plan Fixed income securities 5.9 % 5.5 % 4.6 % Global equity securities 7.2 % 7.2 % 7.2 % Real estate 5.8 % 5.8 % 5.8 % Credit strategies 7.4 % 7.4 % 7.4 % Hedge funds 7.3 % 7.3 % 7.3 % Weighted average 6.3 % 6.3 % 5.8 % 130 Table of Contents Benefit Plan Assumed Health Care Cost Trend Rates The following tables provide information regarding the assumed health care cost trend rates. December 31, 2024 2023 Assumed Health Care Cost Trend Rates-Not Medicare Eligible: Health care cost trend rate assumed for next year 7.00 % 7.00 % Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2034 2033 Assumed Health Care Cost Trend Rates-Medicare Eligible: Health care cost trend rate assumed for next year (Vistra Plan) 15.70 % 12.90 % Health care cost trend rate assumed for next year (Split-Participant Plan) 13.80 % 12.30 % Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2034 2033 Significant Concentrations of Risk The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses. Assumed Discount Rate We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2024 consisted of 490 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings. Contributions Contributions to the Retirement Plan for the years ended December 31, 2024, 2023, and 2022 totaled $ 19 million, zero , and zero , respectively, and contributions in 2025 are expected to total $ 25 million. OPEB plan funding for each of the years ended December 31, 2024, 2023, and 2022 totaled $ 8 million, $ 9 million, and $ 9 million, respectively, and funding in 2025 is expected to total $ 8 million. Future Benefit Payments Estimated future benefit payments to beneficiaries are as follows: 2025 2026 2027 2028 2029 2030-2034 (in millions) Pension benefits $ 33 $ 34 $ 43 $ 32 $ 32 $ 151 OPEB $ 9 $ 9 $ 9 $ 8 $ 8 $ 36 131 Table of Contents Qualified Savings Plans Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75 % of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1 % to 20 % of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100 % ( 75 % for employees covered under the traditional formula in the Retirement Plan) of the first 6 % of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options. Aggregate employer contributions to the qualified savings plans totaled $ 46 million, $ 33 million, and $ 33 million for the years ended December 31, 2024, 2023, and 2022, respectively. 15. COMMITMENTS AND CONTINGENCIES Contractual Commitments As of December 31, 2024, we had minimum contractual commitments under long-term service and maintenance contracts, energy-related contracts and other agreements as follows: Long-Term Service and Maintenance Contracts (a) Coal transportation agreements Pipeline transportation and storage reservation fees Water Contracts (in millions) 2025 $ 227 $ 59 $ 187 $ 9 2026 206 26 200 9 2027 207 26 209 9 2028 265 — 228 9 2029 259 — 234 9 Thereafter 1,916 — 115 37 Total $ 3,080 $ 111 $ 1,173 $ 82 ____________ (a) Long-term service and maintenance contracts reflect expected expenditures as these contracts do not include minimum spending requirements, but can only be terminated based on events outside the control of the Company. In addition to the commitments detailed above, we have nuclear fuel contracts with early termination penalties. As of December 31, 2024, termination costs of $ 116 million would be incurred if we terminated those contracts. Expenditures under our coal purchase and coal transportation agreements totaled $ 744 million, $ 936 million, and $ 995 million for the years ended December 31, 2024, 2023, and 2022, respectively. Guarantees We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Letters of Credit As of December 31, 2024, we had outstanding letters of credit totaling $ 2.935 billion as follows: • $ 2.560 billion to support commodity risk management and collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs; • $ 248 million to support battery and solar development projects; • $ 25 million to support executory contracts and insurance agreements; • $ 86 million to support our REP financial requirements with the PUCT; and • $ 16 million for other credit support requirements. 132 Table of Contents Surety Bonds As of December 31, 2024, we had outstanding surety bonds totaling $ 1.087 billion to support performance under various contracts and legal obligations in the normal course of business. Litigation and Regulatory Proceedings Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material. Litigation Natural Gas Index Pricing Litigation — We, through our subsidiaries, and another company remain named as defendants in one consolidated putative class action lawsuit pending in federal court in Wisconsin claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading, and churn trading from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes. In April 2023, the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit Court) heard oral argument on an interlocutory appeal challenging the district court's order certifying a class. Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius in July 2019. The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 5 -year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint. Ohio House Bill 6 ("HB6") — In July 2019, Ohio adopted a law referred to as HB6, which, among other things, provided subsidies for two nuclear power plants which we acquired in March 2024 upon the closing of our merger with Energy Harbor. We had opposed enactment of that subsidy legislation at the time, and the nuclear subsidies were repealed in 2021 prior to any subsidies being distributed. The U.S. Attorney's Office conducted an investigation into the activities related to the passage of HB6, and Energy Harbor received a grand jury subpoena in July 2020 requiring production of certain information related to that investigation. Energy Harbor completed its responses to that subpoena by December 2021. In August 2020, the Ohio Attorney General filed a civil Racketeer Influenced and Corrupt Organizations Act (RICO) complaint against FirstEnergy Corp. and various Energy Harbor companies related to passage of HB6 ( State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. , Franklin County, Ohio Common Pleas Court Case No. 20CV006281 and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. Energy Harbor Corp. , et al., Franklin County, Ohio Common Pleas Court Case No. 20CV007386). Motions to dismiss those cases remain pending and the case is currently stayed. 133 Table of Contents Winter Storm Uri Legal Proceedings Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, and the Texas Attorney General initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges for generators arising from the event, including performance and fuel and supply issues. We responded to all those investigatory requests. In addition, a large number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been, and continue to be, filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. We and other defendants requested that all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL) pretrial judge. In June 2021, the MDL panel granted the request to consolidate all these cases into an MDL for pretrial proceedings. Additional personal injury cases that have been, and continue to be, filed on behalf of additional plaintiffs have been consolidated with the MDL proceedings. In addition, in January 2022, an insurance subrogation lawsuit was filed in Austin state court by over one hundred insurance companies against ERCOT, Vistra and several other defendants. The lawsuit seeks recovery of insurance funds paid out by these insurance companies to various policyholders for claims related to Winter Storm Uri, and that case has also now been consolidated with the MDL proceedings. In the summer of 2022, various defendant groups filed motions to dismiss five so-called bellwether cases, and the MDL court heard oral argument on those motions in October 2022. In January 2023, the MDL court ruled on the various motions to dismiss and denied the motions to dismiss of the generator defendants and the transmission distribution utilities defendants, but granted the motions of some of the other defendant groups, including the retail electric providers and ERCOT. In February 2023, the generator defendants filed a mandamus petition with the First Court of Appeals in Houston, Texas (First Court of Appeals) to review the MDL court's denial of the motion to dismiss. In December 2023, the First Court of Appeals in a unanimous decision granted our mandamus petition and instructed the MDL court to grant the motions to dismiss in full filed by the generator defendants. In January 2024, the plaintiffs filed a request with the full Court of Appeals to review that panel ruling, which was denied in November 2024. The plaintiffs have petitioned the Texas Supreme Court to review that decision. We believe we have strong defenses to these lawsuits and intend to defend against these cases vigorously if they continue. Moss Landing 300 Battery Fire On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site. We are working closely with all local, state, and federal regulatory authorities on the response, and we are investigating the cause of the fire. We are also responding to various regulatory bodies, including the CPUC, the EPA, and others investigating the incident. Finally, two lawsuits have been filed in California state court against Vistra, LG, and others, arising from the event. Unleashing American Energy Executive Order In January 2025, President Trump issued a series of executive orders, including an order titled Unleashing American Energy (the Order) that ordered that all federal agencies are to review all existing regulations, orders, and other actions for consistency with the policy goals, and develop an action plan within 30 days to resolve any policy inconsistencies. The Order requires the EPA to review the GHG, CSAPR, Legacy CCR and ELG rules discussed below. Additionally, the Order states the U.S. Attorney General may request a stay of the litigation involving these rules while the EPA conducts its reviews. 134 Table of Contents Greenhouse Gas Emissions (GHG) In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing. Starting in 2030, the rule would begin to require more CO 2 emissions control at certain existing fossil fuel-fired steam generating units, with more stringent standards beginning in 2032 for coal-fired units that plan to operate for a longer period of time. For new natural gas combustion turbines that operate more frequently, the rule would phase in increasingly stringent CO 2 requirements over time. Under the rule, states would be required to submit plans to the EPA within 24 months of the rule's publication in the Federal Register that provide for the establishment, implementation, and enforcement of standards of performance for existing sources. These state plans must generally establish standards that are at least as stringent as the EPA's emission guidelines. Under the rule, existing coal-fired steam generation units that will operate on or after January 1, 2039 must start complying with their standards of performance (based on application of CCS with 90 percent capture) by January 1, 2032. Units that are permanently retiring before January 1, 2039, but after December 31, 2031, must start complying with their standards of performance (based on co-firing with 40 percent natural gas on a heat input basis) beginning on January 1, 2030. Units permanently retiring by January 1, 2032 are exempt from the rule. Given our previously announced coal unit retirement commitments, our Martin Lake and Oak Grove plants are the only coal units that are subject to this rule. Our Graham, Lake Hubbard, Stryker Creek and Trinidad oil/natural gas facilities are also regulated under this rule. None of our existing large or small combustion turbines are subject to this rule. The rule also regulates any new gas units. For new combustion turbine units, the rule establishes three different categories depending on how intensively those units are operated, with immediate compliance obligations for all three categories but more stringent standards beginning in 2032 only for the category of units operating the most intensively. Following finalization of the rule in May 2024, 17 petitions for review from various states, industry groups, and companies were filed in the D.C. Circuit Court along with multiple motions to stay the rule. We are participating in an industry coalition challenging the rule. In July 2024, the D.C. Circuit Court denied the motions to stay and a number of parties subsequently filed an emergency request with the U.S. Supreme Court to stay the rule which was denied in October 2024. Oral argument on the merits of the legal challenges to the rule was held in December 2024 before the D.C. Circuit Court. In February 2025, the D.C. Circuit granted the unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. Cross-State Air Pollution Rule (CSAPR) and Good Neighbor Plan In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to lower the 8-hour standard for ozone emissions during ozone season (May to September). As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS. In February 2023, the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain trade groups, and others challenged that disapproval in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). In March 2023, those same parties filed motions to stay the EPA's SIP disapproval in the Fifth Circuit Court and the EPA moved to transfer our challenges to the D.C. Circuit Court or have those challenges dismissed. In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS. We, along with many other companies, trade groups, states, and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions. In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP). The FIP applied to 22 states beginning with the 2023 ozone seasons. States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia, and West Virginia. Texas would be moved into the revised (and more restrictive) Group 3 trading program previously established in the Revised CSAPR Update Rule that includes emission budgets for 2023 that the EPA says are achievable through existing controls installed at power plants. Allowances will be limited under the program and will be further reduced beginning in ozone season 2026 to a level that is intended to reduce operating time of coal-fueled power plants during ozone season or force coal plants to retire, particularly those that do not have selective catalytic reduction systems such as our Martin Lake power plant. 135 Table of Contents In May 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a decision on the merits and denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. As a result of the stay, we do not believe the EPA has authority to implement the GNP FIP as to Texas sources pending the resolution of the merits, meaning that Texas will remain in Group 2 and not be subject to any requirements under the GNP FIP at least until the Fifth Circuit Court rules on the merits. Oral argument was heard in December 2023 before the Fifth Circuit Court. In June 2023, the EPA published the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the Fifth Circuit Court. In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the GNP FIP in the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court. After the motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the GNP FIP as to Texas is stayed. In February 2025, the Department of Justice filed a motion on behalf of the EPA in the Fifth Circuit Court, seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. In February 2025, the State of Texas filed a response opposing the requested abatement, which we joined. In July 2023, the Fifth Circuit Court ruled that the GNP FIP challenge would be held in abeyance pending the resolution of the litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay. In a related action brought by other states and parties challenging the GNP FIP, in June 2024, the U.S. Supreme Court granted a stay of the GNP FIP pending a review of the merits by the D.C. Circuit Court and any further appeal to the U.S. Supreme Court. As a result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP. In February 2025, the D.C. Circuit Court denied a motion filed by the Department of Justice on behalf of the EPA, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 SIP and a partial FIP. For SO 2 , the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generation units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2, and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. For NO X , the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas' SIP that determines that no electricity generation units are subject to BART for particulate matter. In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit Court, where we have intervened in support of the EPA. We are in compliance with the rule, and the retirements of our Monticello, Big Brown, and Sandow 4 plants have enhanced our ability to comply. The EPA is in the process of reconsidering the BART rule, and the challenges in the D.C. Circuit Court have been held in abeyance pending the EPA's final action on reconsideration. In May 2023, a proposed BART rule was published in the Federal Register that would withdraw the trading program provisions of the prior rule and would establish SO 2 limits on six facilities in Texas, including Martin Lake and Coleto Creek. Under the current proposal, compliance would be required within 3 years for Martin Lake and 5 years for Coleto Creek. Due to the announced shutdown for Coleto Creek, we do not anticipate any impacts at that facility, and we are evaluating potential compliance options at Martin Lake should this proposal become final. We submitted comments to the EPA on this proposal in August 2023. 136 Table of Contents SO 2 Designations for Texas In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable. In May 2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring data supporting an attainment designation. In June 2021, the EPA published two notices; one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations. We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, and this case was argued before the Fifth Circuit Court in July 2022. In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO 2 emissions from the plant. The proposed agreed order associated with the SIP proposal reduced emission limits as of January 2022. Emission reductions required are those necessary to demonstrate attainment with the NAAQS. The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval. In January 2024, in a split decision, the Fifth Circuit Court denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO 2 for the area around Martin Lake. As a result of this decision, the EPA's nonattainment designation – originally made in 2016 – remains in place. In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January 2024, which remains pending before the full Fifth Circuit Court. In August 2024, the EPA proposed a Finding of Failure to attain the SO 2 standard for Rusk and Panola Counties, a partial approval and partial disapproval of the Texas SIP and a proposed federal plan for the area. In December 2024, the EPA finalized the Finding of Failure to attain the standard and stated that it would take final action of the SIP partial approval and disapproval in a future action. In February 2025, we, along with the State of Texas, filed a challenge to the Finding of Failure in the Fifth Circuit Court. Particulate Matte r In February 2024, the EPA issued a rule addressing the annual health-based national ambient air quality standards for fine particulate matter (or PM2.5). In general, the rule lowers the level of the annual PM2.5 standard from 12.0 micrograms per cubic meter (µg/m3) to 9.0 µg/m3. The effective date of the rule is 60 days from publication in the Federal Register, and the earliest attainment date for areas exceeding the new standard is 2032. Based on 2021-2023 design value associated with the rule, we have just four plants (Calumet (Illinois), Dicks Creek and Miami Fort (Ohio), and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard. We have previously announced that our Miami Fort generation facility will close by the end of 2027. States will have to develop a plan (by late 2027 at the earliest) to get those areas into attainment and there would be a possibility that additional controls would be required for those sites. However, before the state begins this planning process, the designation process will occur within two years from the issuance of the final rule. The states develop recommendations about the boundaries of the nonattainment counties and the EPA must finalize the designations including the boundaries of each nonattainment area. 137 Table of Contents Effluent Limitation Guidelines (ELGs) In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash, and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. The EPA published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Notifications were made to Texas, Illinois, and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. In May 2024, the EPA published the final ELG rule revisions, which contain new requirements for legacy wastewater and combustion residual leachate. The final rule also leaves in place the subcategory for facilities that permanently cease coal combustion by 2028. We are reviewing the rule for impact but believe it will require additional treatment costs for legacy wastewaters during pond closure activities and combustion residual leachate. At this time, we don't expect the impact of these additional treatment costs to be material. A number of parties have since challenged the rule and that case is pending in the U.S. Court of Appeals for the Eighth Circuit. We are not a party to that litigation. In February 2025, the Department of Justice on behalf of the EPA filed an unopposed motion seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. Coal Combustion Residuals (CCR) Rule Revisions and Extension Applications In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a final rule establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The 2020 final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue). Prior to the November 2020 deadline to seek extensions, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications. Legacy CCR Rulemaking In May 2024, the EPA published a final rule that expands coverage of groundwater monitoring and closure requirements to the following two new categories of units: (a) legacy CCR surface impoundments which are CCR surface impoundments that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015 and (b) "CCR management units" (CCRMUs) which generally could encompass noncontainerized ash deposits greater than one ton and impoundments and landfills that closed prior to October 19, 2015. As part of the rule, the EPA identified numerous CCR management units across the country, including ten of our potential units. The Vermilion ash ponds discussed below are the only unit which we believe qualify as a legacy CCR surface impoundment and given our closure plan for that site we do not believe the rule will have any impact on that site. CCRMUs with 1,000 or more tons of CCR must comply with the CCR's groundwater monitoring, corrective action, closure and post-closure requirements. For CCRMUs, complete facility evaluation reports are due within 33 months after publication of the rule, initial groundwater reports are due January 31, 2029, and the deadline to initiate closure, if needed, will start in 2029. Closure of the CCRMUs may also be deferred beyond those dates depending on certain factors, including where the CCRMU is located beneath critical infrastructure. In addition, certain closures may not be required when closure was previously approved under a state program. Because facility evaluation reports will determine our unit-specific compliance obligations, we cannot determine them at this time. In August 2024, we, along with USWAG, several other generating companies, and 17 states, including Texas, filed a challenge to the rule in the D.C. Circuit Court. In February 2025, the D.C. Circuit Court granted an unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. 138 Table of Contents MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility. At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments ( i.e. , the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the Illinois Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash. These proposed closure costs are reflected in the ARO in the consolidated balance sheets (see Note 13 for additional information). In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule. In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of guidelines, rules, and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal at any site. In May 2021, we, along with other industry petitioners, filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule. In March 2024, the Illinois Fourth Judicial District issued a decision denying the industry petitions. We do not anticipate any impacts from this decision. In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in January 2022 and five of our sites in July 2022. One additional closure construction application was filed for our Baldwin facility in August 2023. For all of the above CCR matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not require removal. However, the rule required us to undertake further site-specific evaluations required by each program. We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been approved by the IEPA and as such, an estimate of such costs cannot be made. The CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the costs of closure methods that our operations and environmental services teams determined were appropriate based on the existing closure requirements at the time we recorded those ARO liabilities, and is reasonably possible for those to increase once the IEPA determines final closure requirements. Once the IEPA acts on our permit applications, we will reassess the decommissioning costs and adjust our ARO liabilities accordingly. 139 Table of Contents MISO 2015-2016 Planning Resource Auction In May 2015, three complaints were filed at the FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by the Complainants. We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff in connection with the PRA and disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at the FERC against MISO in June 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint with respect to Dynegy's conduct alleged in the complaint. In October 2015, the FERC issued an order of nonpublic, formal investigation (the investigation) into whether market manipulation or other potential violations of the FERC orders, rules and regulations occurred before or during the PRA. In December 2015, the FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction. The order did not address the arguments of the Complainants regarding the PRA and stated that those issues remained under consideration and would be addressed in a future order. In July 2019, the FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed. The FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff. A request for rehearing was denied by the FERC in March 2020. The order was appealed by Public Citizen, Inc. to the D.C. Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing Company intervened in the case in June 2020. In August 2021, the D.C. Circuit Court issued a ruling denying Public Citizen, Inc.'s arguments that the FERC failed to meet its obligation to ensure just and reasonable rates because it did not review the prices resulting from the auction before those prices went into effect and that the FERC was arbitrary and capricious in failing to adequately explain its decision to close its investigation into whether Dynegy engaged in market manipulation. The D.C. Circuit Court of Appeals granted Public Citizen, Inc.'s petition in part finding that the FERC's decision that the auction results were just and reasonable solely because the auction process complied with the filed tariff was unreasoned and remanded the case back to the FERC for further proceedings on that issue. On February 4, 2022 the Illinois Attorney General and Public Citizen, Inc. filed a motion at the FERC requesting that the FERC on remand reverse its prior decision and either find that auction results were not just and reasonable and order Dynegy to pay refunds to Illinois or, in the alternative, initiate an evidentiary hearing and discovery. In June 2022, the FERC issued an order on remand establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 planning resource auction. Although the FERC directed the Office of Enforcement to file a remand report, the FERC stated in the June 2022 order that it is not reopening the Office of Enforcement investigation. In September 2022, the Office of Enforcement filed its remand report stating that the Office of Enforcement staff found during its investigation that Dynegy knowingly engaged in manipulative behavior to set the Zone 4 price in the 2015-2016 PRA. In June 2023, the Company filed its initial brief and response to the remand report, and in August 2023 the Company filed a reply to the initial briefs from other parties. In June 2024, the FERC issued an order for an evidentiary hearing (or a trial before a FERC administrative law judge) to determine what the FERC cited as "disputed issues of material fact" that it believes cannot be resolved on the existing record and, in October 2024, issued an order dismissing our request for rehearing of the June 2024 order. We will continue to vigorously defend our position. Other Matters We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity, or financial condition. 140 Table of Contents Labor Contracts We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by collective bargaining agreements. The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal-, natural gas-, and nuclear-fueled generation operations, as well as some battery operations, expire on various dates between February 2025 and March 2028, but remain effective thereafter unless and until terminated by either party. While we cannot predict the outcome of labor contract negotiations, we do not expect any changes in our existing agreements to have a material adverse effect on our results of operations, liquidity, or financial condition. Nuclear Insurance Nuclear insurance includes nuclear liability coverage, property damage, nuclear accident decontamination, and accidental premature decommissioning coverage, and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity, or financial condition. With regard to nuclear liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $ 16.2 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $ 16.2 billion limit for a single incident. As required, we insure against a possible nuclear incident at our nuclear facilities resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP). Under the SFP, in the event of any single nuclear liability loss in excess of $ 500 million at any nuclear generation facility in the U.S., each operating licensed reactor in the U.S. is subject to an assessment of up to $ 165.9 million. This approximately $ 165.9 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur by November 2028. Assessments are currently limited to $ 24.7 million per operating licensed reactor per year per incident. As of December 31, 2024, our maximum potential assessment under the industry retrospective plan would be approximately $ 995.4 million per incident but no more than $ 148.2 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $ 500 million per accident at any nuclear facility. The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $ 1.06 billion of nuclear accident decontamination and reactor damage stabilization insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance for our Comanche Peak facility in the amount of $ 2.25 billion and non-nuclear accident related property damage in the amount of $ 1.0 billion (subject to a $ 5 million deductible per accident except for natural hazards which are subject to a $ 9.5 million deductible per accident), and losses excluded or above such limits are self-insured. We maintain nuclear accident decontamination and reactor damage stabilization insurance and non-nuclear accident related property damage for our Beaver Valley, Davis-Besse and Perry facilities in the amount of $ 1.5 billion each (subject to a $ 20 million deductible per accident), and losses excluded or above such limits are self-insured. 141 Table of Contents We also maintain Accidental Outage insurance to help cover the additional costs of obtaining replacement electricity from another source if the units are out of service for more than twelve weeks as a result of covered direct physical damage. Coverage at Comanche Peak provides for weekly payments per unit up to $ 4.5 million for the first 52 weeks and up to $ 2.7 million for a remaining 21 weeks for non-nuclear and up to $ 3.6 million for a remaining 71 weeks for nuclear property damage outages. The total maximum coverage is $ 291 million for non-nuclear property damage and $ 490 million for nuclear property damage outages. Coverage at Beaver Valley, Davis-Besse and Perry facilities provide for weekly payments per unit up to $ 2.5 million for the first 52 weeks and up to $ 1.5 million for a remaining 52 weeks for non-nuclear and up to $ 2 million for a remaining 110 weeks for nuclear property damage outages. The total maximum coverage is $ 208 million for non-nuclear property damage and $ 350 million for nuclear damage outages. There are two units at Comanche Peak and Beaver Valley, and coverage amounts applicable to each unit will reduce to 80 % if both units are out of service at the same time as a result of the same accident. 16. EQUITY Common Stock Issuances and Repurchases Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2024, 2023, and 2022 are reflected in the table below. Shares Issued Treasury Shares Shares Outstanding Balance at December 31, 2021 532,929,476 ( 69,031,742 ) 463,897,734 Shares issued (a) 4,262,575 — 4,262,575 Shares retired ( 12,979 ) — ( 12,979 ) Shares repurchased (b) — ( 78,470,547 ) ( 78,470,547 ) Balance at December 31, 2022 537,179,072 ( 147,502,289 ) 389,676,783 Shares issued (a) 6,474,491 — 6,474,491 Shares retired ( 18,391 ) — ( 18,391 ) Shares repurchased (b) — ( 44,994,499 ) ( 44,994,499 ) Balance at December 31, 2023 543,635,172 ( 192,496,788 ) 351,138,384 Shares issued (a) 5,117,434 — 5,117,434 Shares repurchased (b) — ( 16,560,328 ) ( 16,560,328 ) Balance at December 31, 2024 548,752,606 ( 209,057,116 ) 339,695,490 ____________ (a) Shares issued include share awards granted to nonemployee directors. (b) Shares repurchased include 58,817 , 318,632 , and 78,087 of unsettled shares as of December 31, 2024, 2023, and 2022, respectively. C ommon Stock Dividends Dividends are subject to declaration by the Board and may be subject to numerous factors at the time of declaration. These factors include, but are not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law, and any contractual limitations, such as the cumulative dividend requirements described in the certificates of designation of our outstanding preferred stock. Dividends per common share totaled $ 0.8735 , $ 0.8205 , and $ 0.7240 in the years ended December 31, 2024, 2023, and 2022, respectively. In February 2025, the Board declared a quarterly dividend of $ 0.2235 per share of common stock that will be paid in March 2025. 142 Table of Contents Share Repurchase Program In October 2021, the Board authorized a share repurchase program (Share Repurchase Program). Under this program, shares of the Company's common stock may be repurchased in open market transactions, privately negotiated transactions, or other means in accordance with federal securities laws. The timing, number, and value of shares repurchased will be determined at our discretion, considering factors such as capital allocation priorities, stock market price, general market and economic conditions, legal requirements, and compliance with debt agreements and preferred stock certificates of designation. Amount Authorized for Share Repurchases (in billions) Board Authorization Dates: October 2021 $ 2.00 August 2022 1.25 March 2023 1.00 February 2024 1.50 October 2024 1.00 Cumulative authorization at December 31, 2024 $ 6.75 The following table provides information about our repurchases of common stock for the period between January 1, 2022 and February 24, 2025. $6.750 Billion Board Authorization Total Number of Shares Repurchased Average Price Paid Per Share Amount Paid for Shares Repurchased Amount Available for Additional Repurchases at the End of the Period (in millions, except share amounts and price paid per share) Year Ended December 31, 2022 78,470,547 $ 23.40 $ 1,836 Year Ended December 31, 2023 44,994,499 27.89 1,255 Year Ended December 31, 2024 16,560,328 74.96 1,241 January 1, 2022 through December 31, 2024 (a) 140,025,374 $ 30.94 $ 4,332 $ 2,009 January 1, 2025 through February 24, 2025 848,866 163.23 139 January 1, 2022 through February 24, 2025 140,874,240 $ 31.74 $ 4,471 $ 1,870 ____________ (a) Shares repurchased include 58,817 of unsettled shares for $ 8 million as of December 31, 2024. Preferred Stock The following is a summary of our cumulative redeemable preferred stock outstanding. In the event of liquidation or dissolution of the Company, the payment of dividends and the distribution of assets to preferred stockholders takes precedence over the Company's common stockholders. Preferred Stock Series Issuance Date Shares Issued and Outstanding (a) Contractual Rates Earliest Redemption Date (b) Date at Which Dividend Rate Becomes Floating Floating Annual Rates Series A October 15, 2021 1,000,000 8.000 % October 15, 2026 October 15, 2026 5-Year U.S. Treasury rate (subject to floor of 1.07 %) plus 6.93 % Series B December 10, 2021 1,000,000 7.000 % December 15, 2026 December 15, 2026 5-Year U.S. Treasury rate (subject to floor of 1.26 %) plus 5.74 % Series C December 29, 2023 476,066 8.875 % January 15, 2029 January 15, 2029 5-Year U.S. Treasury rate (subject to floor of 3.83 %) plus 5.045 % ____________ (a) Series C Preferred Stock issued totaled 476,081 shares at December 31, 2023. (b) Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date. 143 Table of Contents Each series of preferred stock has a liquidation price of $ 1,000 , plus accrued and unpaid dividends through their redemption date. Preferred stock is not convertible into or exchangeable for any other securities of the Company and has limited voting rights. Preferred Stock Dividends Preferred stock dividends are payable semiannually in arrears when declared by the Board. The following table summarizes preferred stock dividends paid per share in the years ended December 31, 2024, 2023, and 2022. Year Ended December 31, Preferred Stock Series 2024 2023 2022 Series A Preferred Stock $ 80.00 $ 80.00 $ 80.00 Series B Preferred Stock $ 70.00 $ 70.00 $ 70.97 Series C Preferred Stock $ 48.32 In October 2024, the Board declared a semi-annual dividend of $ 44.375 per share of Series C Preferred Stock that was paid in January 2025. In February 2025, the Board declared a semi-annual dividend of $ 40.00 per share of Series A Preferred Stock that will be paid in April 2025. 17. EARNINGS PER SHARE Basic earnings per share available to common stockholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements. Year Ended December 31, 2024 2023 2022 (in millions, except share data) Net income (loss) attributable to Vistra $ 2,659 $ 1,493 $ ( 1,227 ) Less cumulative dividends attributable to Series A Preferred Stock ( 80 ) ( 80 ) ( 80 ) Less cumulative dividends attributable to Series B Preferred Stock ( 70 ) ( 70 ) ( 70 ) Less cumulative dividends attributable to Series C Preferred Stock ( 42 ) — — Net income (loss) attributable to common stock — basic and diluted 2,467 1,343 ( 1,377 ) Weighted average shares of common stock outstanding: Basic 344,788,634 369,771,359 422,447,074 Dilutive securities: Stock-based incentive compensation plan 7,778,426 5,421,752 — Diluted 352,567,060 375,193,110 422,447,074 Net income (loss) per weighted average share of common stock outstanding: Basic $ 7.16 $ 3.63 $ ( 3.26 ) Diluted $ 7.00 $ 3.58 $ ( 3.26 ) Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive were immaterial in the year ended December 31, 2024 and were 392,218 and 8,292,647 shares for the years ended December 31, 2023 and 2022, respectively. 144 Table of Contents 18. STOCK-BASED COMPENSATION Vistra 2016 Omnibus Incentive Plan On the Effective Date, the Board adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons. Following approval of the Board and approval by the stockholders at the 2019 and 2024 annual meetings of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000 and 43,000,000 , respectively. The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards, and (c) establish the terms and conditions of awards, including the price (if any) to be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock options, RSUs, restricted stock, performance awards, and other forms of awards granted or denominated in shares of Vistra common stock, as well as certain cash-based awards. If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised award shall again be available for awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation. No awards under the 2016 Incentive Plan have been settled in cash since the Effective Date. As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra stockholders. Stock-Based Compensation Expense Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows: Year Ended December 31, 2024 2023 2022 (in millions) Total stock-based compensation expense $ 100 $ 77 $ 65 Income tax benefit ( 23 ) ( 18 ) ( 15 ) Stock based-compensation expense, net of tax $ 77 $ 59 $ 50 Stock Options Stock options outstanding at December 31, 2024 are all held by current or former employees. The following table summarizes our stock option activity: Year Ended December 31, 2024 Stock Options (in thousands) Weighted Average Exercise Price Weighted Average Remaining Contractual Term (Years) Aggregate Intrinsic Value (in millions) Total outstanding at beginning of period 6,126 $ 20.01 4.2 $ 113.5 Exercised ( 2,526 ) $ 20.06 Total outstanding at end of period 3,600 $ 19.97 3.5 $ 424.4 Exercisable at December 31, 2024 3,600 $ 19.97 3.5 $ 424.4 As of December 31, 2024, there was no unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan and no new options were issued in the three years ended December 31, 2024. 145 Table of Contents Restricted Stock Units The following table summarizes our restricted stock unit activity: Year Ended December 31, 2024 Restricted Stock Units (in thousands) Weighted Average Grant Date Fair Value Total nonvested at beginning of period 3,908 $ 21.90 Granted 1,017 $ 59.11 Vested ( 1,785 ) $ 22.20 Forfeited ( 86 ) $ 33.55 Total nonvested at end of period 3,054 $ 34.30 As of December 31, 2024, $ 61 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2.0 years. Performance Stock Units We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis. All PSUs have a three year performance period and a payout opportunity of 0 - 200 % of target ( 100 %), which is intended to be settled in shares of Vistra common stock. We recognized compensation expense associated with PSUs of $ 54 million, $ 36 million, and $ 22 million for the years ended December 31, 2024, 2023, and 2022, respectively. As of December 31, 2024, we have $ 64 million of unrecognized compensation cost associated with PSUs. 19. SEGMENT INFORMATION The operations of Vistra are aligned into five reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. In the fourth quarter of 2024, we updated our reportable segments to reflect changes in how the Company's CODM makes operating decisions, assesses performance, and allocates resources by removing the Sunset segment. The results of the plants previously included in the Sunset segment are now reflected in the Texas and East segments based on their respective geography. Our Chief Executive Officer is our CODM. Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources. The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial and industrial customers. Substantially all of these activities are conducted by TXU Energy, Ambit, Dynegy Energy Services, Homefield Energy, Energy Harbor, and U.S. Gas & Electric across 16 states and the District of Columbia. The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel procurement, and logistics management. The Texas segment represents results from all of Vistra's electricity generation operations in the ERCOT market except for assets included in the Asset Closure segments. The East segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets included in the Asset Closure segment, and includes operations in the PJM, MISO, ISO-NE, and NYISO markets. The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 6 for additional information). Upon movement of generation plant assets to the Asset Closure segment, prior year results are retrospectively adjusted, if the effects are material, for comparative purposes. Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines. 146 Table of Contents Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses not allocated to our operating segments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. Our CODM uses more than one measure to assess segment performance, but primarily focuses on Adjusted EBITDA. While we believe this is a useful metric in evaluating operating performance, it is not a metric defined by U.S. GAAP and may not be comparable to non-GAAP metrics presented by other companies. Adjusted EBITDA is most comparable to consolidated Net income (loss) prepared based on U.S. GAAP. The CODM uses net income in competitive analysis by benchmarking to the Company's competitors and in evaluating drivers of segment profits available to the Company's equity holders. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments. Substantially all income tax (expense) benefit is recognized in Corporate and Other. Year Ended December 31, 2024 Retail Texas East West Asset Closure Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ 24,730 $ ( 7,506 ) $ 17,224 Fuel, purchased power costs, and delivery fees ( 10,276 ) ( 1,596 ) ( 2,698 ) ( 221 ) ( 3 ) ( 14,794 ) 7,509 ( 7,285 ) Operating costs ( 159 ) ( 996 ) ( 1,103 ) ( 72 ) ( 81 ) ( 2,411 ) ( 3 ) ( 2,414 ) Selling, general, and administrative expenses ( 977 ) ( 169 ) ( 148 ) ( 25 ) ( 43 ) ( 1,362 ) ( 239 ) ( 1,601 ) Other segment items: Depreciation and amortization ( 114 ) ( 581 ) ( 996 ) ( 86 ) — ( 1,777 ) ( 66 ) ( 1,843 ) Interest expenses and related charges ( 54 ) 46 9 1 ( 4 ) ( 2 ) ( 898 ) ( 900 ) Income tax expense — — — — — — ( 655 ) ( 655 ) Other (a) ( 1 ) 35 177 ( 3 ) 14 222 64 286 Net income (loss) $ 1,216 $ 2,133 $ 902 $ 471 $ ( 116 ) $ 4,606 $ ( 1,794 ) $ 2,812 Capital expenditures, including nuclear fuel and excluding growth expenditures $ 4 $ 1,124 $ 661 $ 70 $ — $ 1,859 $ 58 $ 1,917 Year Ended December 31, 2023 Retail Texas East West Asset Closure (b) Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ 21,355 $ ( 6,576 ) $ 14,779 Fuel, purchased power costs, and delivery fees ( 9,046 ) ( 2,028 ) ( 2,730 ) ( 328 ) ( 3 ) ( 14,135 ) 6,578 ( 7,557 ) Operating costs ( 123 ) ( 917 ) ( 528 ) ( 58 ) ( 74 ) ( 1,700 ) ( 2 ) ( 1,702 ) Selling, general, and administrative expenses ( 858 ) ( 140 ) ( 127 ) ( 24 ) ( 34 ) ( 1,183 ) ( 125 ) ( 1,308 ) Other segment items: Depreciation and amortization ( 102 ) ( 550 ) ( 703 ) ( 79 ) — ( 1,434 ) ( 68 ) ( 1,502 ) Interest expenses and related charges ( 20 ) 21 ( 2 ) 8 ( 5 ) 2 ( 742 ) ( 740 ) Income tax expense — — ( 1 ) — — ( 1 ) ( 507 ) ( 508 ) Other (a) 1 33 ( 50 ) 21 110 115 ( 85 ) 30 Net income (loss) $ 424 $ 398 $ 1,749 $ 454 $ ( 6 ) $ 3,019 $ ( 1,527 ) $ 1,492 Capital expenditures, including nuclear fuel and excluding growth expenditures $ 1 $ 750 $ 362 $ 366 $ — $ 1,479 $ 58 $ 1,537 147 Table of Contents Year Ended December 31, 2022 Retail Texas East West Asset Closure (b) Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 9,455 $ 3,878 $ 4,429 $ 336 $ 384 $ 18,482 $ ( 4,754 ) $ 13,728 Fuel, purchased power costs, and delivery fees ( 7,169 ) ( 3,052 ) ( 4,132 ) ( 481 ) ( 322 ) ( 15,156 ) 4,755 ( 10,401 ) Operating costs ( 143 ) ( 832 ) ( 482 ) ( 42 ) ( 145 ) ( 1,644 ) ( 1 ) ( 1,645 ) Selling, general, and administrative expenses ( 826 ) ( 135 ) ( 97 ) ( 21 ) ( 44 ) ( 1,123 ) ( 66 ) ( 1,189 ) Other segment items: Interest expenses and related charges ( 14 ) 20 ( 6 ) 6 ( 3 ) 3 ( 371 ) ( 368 ) Depreciation and amortization ( 145 ) ( 541 ) ( 768 ) ( 42 ) ( 31 ) ( 1,527 ) ( 69 ) ( 1,596 ) Income tax benefit — — — — — — 350 350 Other (a) — 76 ( 71 ) 6 14 25 ( 114 ) ( 89 ) Net income (loss) $ 1,158 $ ( 586 ) $ ( 1,127 ) $ ( 238 ) $ ( 147 ) $ ( 940 ) $ ( 270 ) $ ( 1,210 ) Capital expenditures, including nuclear fuel and excluding growth expenditures $ 1 $ 520 $ 187 $ 345 $ — $ 1,053 $ 55 $ 1,108 ____________ (a) Other includes impairment of long-lived assets, other income, other deductions, and the impacts of the Tax Receivable Agreement. (b) We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants retired in 2022 and 2023. See Note 6 for additional information. 20. SUPPLEMENTARY FINANCIAL INFORMATION Other Income and Deductions Year Ended December 31, 2024 2023 2022 (in millions) Other income: NDT net income (a) $ 170 $ — $ — Insurance settlements (b) 23 24 70 Gain on sale of land (c) 6 95 8 Gain on TRA settlement (d) 10 29 — Interest income 65 86 19 All other 38 23 20 Total other income $ 312 $ 257 $ 117 Other deductions: All other $ 21 $ 14 $ 4 Total other deductions $ 21 $ 14 $ 4 ____________ (a) Includes interest, dividends, and net realized and unrealized gains and losses associated with NDTs of the PJM nuclear facilities. Reported in the East segment. (b) For the year ended December 31, 2024, $ 20 million reported in the Texas segment and $ 3 million reported in the West segment. For the year ended December 31, 2023, $ 19 million reported in the West segment and $ 5 million in the Asset Closure segment. For the year ended December 31, 2022, $ 62 million reported in the Texas segment, $ 6 million reported in the West segment, $ 1 million reported in the Asset Closure segment, and $ 1 million reported in the Corporate and Other non-segment. 148 Table of Contents (c) For the year ended December 31, 2024, reported in the Asset Closure segment. For the year ended December 31, 2023, $ 94 million reported in the Asset Closure segment and $ 1 million reported in the Texas segment. For the year ended December 31, 2022, reported in the Asset Closure segment. (d) Reported in the Corporate and Other. Inventories by Major Category December 31, 2024 2023 (in millions) Materials and supplies $ 533 $ 289 Fuel stock 403 420 Natural gas in storage 34 31 Total inventories $ 970 $ 740 Investments December 31, 2024 2023 (in millions) Nuclear decommissioning trusts $ 4,440 $ 1,951 Assets related to employee benefit plans 14 28 Land investments 42 42 Other investments 16 14 Total investments $ 4,512 $ 2,035 Other Noncurrent Liabilities and Deferred Credits The balance of other noncurrent liabilities and deferred credits consists of the following: December 31, 2024 2023 (in millions) Retirement and other employee benefits (Note 14) $ 224 $ 247 Winter Storm Uri impact (a) 1 26 Identifiable intangible liabilities (Note 7) 155 131 Regulatory liability (b) 452 209 Operating lease liabilities 98 48 Finance lease liabilities 218 227 Liability for third-party remediation 8 17 Accrued severance costs 36 36 Other accrued expenses 64 58 Total other noncurrent liabilities and deferred credits $ 1,256 $ 999 ____________ (a) Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri. (b) As of December 31, 2024, the fair value of the assets contained in the Comanche Peak NDT was higher than the carrying value of our ARO related to our nuclear generation plant decommissioning and recorded as a regulatory liability of $ 452 million and $ 209 million, respectively, in other noncurrent liabilities and deferred credits. 149 Table of Contents Supplemental Cash Flow Information The following table reconciles cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows to the amounts reported in the consolidated balance sheets at December 31, 2024 and 2023: December 31, 2024 2023 (in millions) Cash and cash equivalents $ 1,188 $ 3,485 Restricted cash included in current assets (a) 28 40 Restricted cash included in noncurrent assets (a) 6 14 Total cash, cash equivalents and restricted cash $ 1,222 $ 3,539 ____________ (a) Restricted cash consists of amounts related to remediation escrow accounts. Vistra has transferred various asset retirement obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra deposits funds into escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process. Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits. The following table summarizes our supplemental cash flow information for the years ended December 31, 2024, 2023, and 2022, respectively. Non-cash investing and financing activities also includes activity related to the Energy Harbor Merger. See Note 2 for additional information. Year Ended December 31, 2024 2023 2022 (in millions) Cash payments related to: Interest paid $ 987 $ 636 $ 581 Capitalized interest ( 77 ) ( 37 ) ( 29 ) Interest paid (net of capitalized interest) $ 910 $ 599 $ 552 Non-cash investing and financing activities: Accrued property, plant, and equipment additions (a) $ 258 $ 104 $ 103 Issuance of Series C Preferred Stock as consideration for the repurchase of TRA Rights with a carrying value of $ 506 million $ — $ 476 $ — Book value of property, plant, and equipment sold, including nuclear fuel $ 117 $ 26 $ — ____________ (a) Represents property, plant, and equipment accruals during the period for which cash has not been paid as of the end of the period. For the years ended December 31, 2024, 2023, and 2022, we paid federal income taxes of $ 5 million, zero , and $ 1 million, respectively, paid state income taxes of $ 59 million, $ 44 million, and $ 33 million, respectively, and received state tax refunds of $ 9 million, $ 13 million, and $ 8 million, respectively. 150 Table of Contents Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.