filings.toolsItem 1. FINANCIAL STATEMENTS
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Item 1. FINANCIAL STATEMENTS
VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited) (Millions of Dollars, Except Share Data)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Operating revenues | $ | 4,971 | $ | 6,288 | $ | 13,154 | $ | 13,187 | |||||||||||||||
| Fuel, purchased power costs, and delivery fees | (2,370) | (2,207) | (6,791) | (5,520) | |||||||||||||||||||
| Operating costs | (655) | (616) | (2,081) | (1,742) | |||||||||||||||||||
| Depreciation and amortization | (460) | (466) | (1,523) | (1,306) | |||||||||||||||||||
| Selling, general, and administrative expenses | (444) | (411) | (1,254) | (1,137) | |||||||||||||||||||
| Impairment of long-lived assets | (5) | — | (73) | — | |||||||||||||||||||
| Operating income | 1,037 | 2,588 | 1,432 | 3,482 | |||||||||||||||||||
| Other income, net | 105 | 136 | 291 | 282 | |||||||||||||||||||
| Interest expense and related charges | (286) | (332) | (908) | (743) | |||||||||||||||||||
| Impacts of Tax Receivable Agreement | — | — | — | (5) | |||||||||||||||||||
| Net income before income taxes | 856 | 2,392 | 815 | 3,016 | |||||||||||||||||||
| Income tax expense | (204) | (555) | (104) | (694) | |||||||||||||||||||
| Net income | $ | 652 | $ | 1,837 | $ | 711 | $ | 2,322 | |||||||||||||||
| Net (income) loss attributable to noncontrolling interest | — | 51 | — | (104) | |||||||||||||||||||
| Net income attributable to Vistra | $ | 652 | $ | 1,888 | $ | 711 | $ | 2,218 | |||||||||||||||
| Cumulative dividends attributable to preferred stock | (48) | (48) | (144) | (144) | |||||||||||||||||||
| Net income attributable to Vistra common stock | $ | 604 | $ | 1,840 | $ | 567 | $ | 2,074 | |||||||||||||||
| Weighted average shares of common stock outstanding: | |||||||||||||||||||||||
| Basic | 338,749,454 | 342,969,916 | 339,313,294 | 346,315,125 | |||||||||||||||||||
| Diluted | 345,035,160 | 350,203,692 | 346,303,617 | 353,805,937 | |||||||||||||||||||
| Net income per weighted average share of common stock outstanding: | |||||||||||||||||||||||
| Basic | $ | 1.78 | $ | 5.36 | $ | 1.67 | $ | 5.99 | |||||||||||||||
| Diluted | $ | 1.75 | $ | 5.25 | $ | 1.64 | $ | 5.86 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited) (Millions of Dollars)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Net income | $ | 652 | $ | 1,837 | $ | 711 | $ | 2,322 | |||||||||||||||
| Other comprehensive income, net of tax effects: | |||||||||||||||||||||||
| Effects related to pension and other retirement benefit obligations (net of tax expense of $—, $—, $— and $—) | 1 | 1 | — | 1 | |||||||||||||||||||
| Total other comprehensive income | 1 | 1 | — | 1 | |||||||||||||||||||
| Comprehensive income | $ | 653 | $ | 1,838 | $ | 711 | $ | 2,323 | |||||||||||||||
| Comprehensive (income) loss attributable to noncontrolling interest | — | 51 | — | (104) | |||||||||||||||||||
| Comprehensive income attributable to Vistra | $ | 653 | $ | 1,889 | $ | 711 | $ | 2,219 |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data) | |||||||||||
| September 30, 2025 | December 31, 2024 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 602 | $ | 1,188 | |||||||
| Restricted cash | 30 | 28 | |||||||||
| Trade accounts receivable — net | 2,327 | 1,982 | |||||||||
| Inventories | 970 | 970 | |||||||||
| Commodity and other derivative contractual assets | 2,634 | 2,587 | |||||||||
| Margin deposits related to commodity contracts | 721 | 406 | |||||||||
| Margin deposits posted under affiliate financing agreement | 450 | 435 | |||||||||
| Prepaid expense and other current assets | 647 | 523 | |||||||||
| Total current assets | 8,381 | 8,119 | |||||||||
| Restricted cash | 6 | 6 | |||||||||
| Investments | 5,008 | 4,512 | |||||||||
| Property, plant and equipment — net | 17,725 | 18,173 | |||||||||
| Goodwill | 2,810 | 2,807 | |||||||||
| Identifiable intangible assets — net | 2,097 | 2,213 | |||||||||
| Commodity and other derivative contractual assets | 604 | 740 | |||||||||
| Accumulated deferred income taxes | 9 | 9 | |||||||||
| Other noncurrent assets | 1,380 | 1,191 | |||||||||
| Total assets | $ | 38,020 | $ | 37,770 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts receivable financing | $ | 1,225 | $ | 750 | |||||||
| Long-term debt due currently | 231 | 880 | |||||||||
| Forward repurchase obligation due currently | 701 | 703 | |||||||||
| Trade accounts payable | 1,362 | 1,510 | |||||||||
| Commodity and other derivative contractual liabilities | 3,610 | 3,351 | |||||||||
| Margin deposits related to commodity contracts | 3 | 49 | |||||||||
| Accrued taxes other than income | 180 | 209 | |||||||||
| Accrued interest | 225 | 193 | |||||||||
| Asset retirement obligations | 202 | 142 | |||||||||
| Other current liabilities | 687 | 645 | |||||||||
| Total current liabilities | 8,426 | 8,432 | |||||||||
| Margin deposits financing with affiliate | 450 | 435 | |||||||||
| Long-term debt, less amounts due currently | 15,757 | 15,418 | |||||||||
| Forward repurchase obligation, less amounts due currently | 613 | 632 | |||||||||
| Commodity and other derivative contractual liabilities | 1,388 | 1,367 | |||||||||
| Accumulated deferred income taxes | 765 | 697 | |||||||||
| Asset retirement obligations | 3,944 | 3,936 | |||||||||
| Other noncurrent liabilities and deferred credits | 1,454 | 1,270 | |||||||||
| Total liabilities | 32,797 | 32,187 |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data) | |||||||||||
| September 30, 2025 | December 31, 2024 | ||||||||||
| Commitments and Contingencies | |||||||||||
| Total equity: | |||||||||||
| Preferred stock (100,000,000 shares authorized, $1,000 liquidation preference per share, 2,476,066 shares outstanding at both September 30, 2025 and December 31, 2024, respectively) | 2,476 | 2,476 | |||||||||
| Common stock (par value $0.01 per share, 1,800,000,000 shares authorized, 338,679,644 and 339,754,307 shares outstanding at September 30, 2025 and December 31, 2024, respectively) | 5 | 5 | |||||||||
| Treasury stock, at cost (214,210,252 and 208,998,299 shares at September 30, 2025 and December 31, 2024, respectively) | (6,675) | (5,912) | |||||||||
| Additional paid-in-capital | 9,491 | 9,435 | |||||||||
| Accumulated deficit | (107) | (454) | |||||||||
| Accumulated other comprehensive income | 20 | 20 | |||||||||
| Stockholders' equity | 5,210 | 5,570 | |||||||||
| Noncontrolling interest in subsidiary | 13 | 13 | |||||||||
| Total equity | 5,223 | 5,583 | |||||||||
| Total liabilities and equity | $ | 38,020 | $ | 37,770 |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars) | |||||||||||
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| Cash flows — operating activities: | |||||||||||
| Net income | $ | 711 | $ | 2,322 | |||||||
| Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||
| Depreciation and amortization | 2,225 | 1,891 | |||||||||
| Deferred income tax expense (benefit), net | 68 | 666 | |||||||||
| Impairment of long-lived and other assets | 73 | — | |||||||||
| Unrealized net (gain) loss from mark-to-market valuations of commodities | 367 | (1,725) | |||||||||
| Unrealized net loss from mark-to-market valuations of interest rate swaps | 84 | 26 | |||||||||
| Unrealized net gain from nuclear decommissioning trusts | (164) | (133) | |||||||||
| Asset retirement obligation accretion expense | 100 | 84 | |||||||||
| Bad debt expense | 152 | 132 | |||||||||
| Stock-based compensation expense | 82 | 76 | |||||||||
| Involuntary conversion gain | (80) | — | |||||||||
| Other, net | 36 | (14) | |||||||||
| Changes in operating assets and liabilities: | |||||||||||
| Margin deposits, net | (361) | 855 | |||||||||
| Accrued interest | 32 | 11 | |||||||||
| Accrued taxes | (19) | (40) | |||||||||
| Accrued employee incentive | (106) | (78) | |||||||||
| Other operating assets and liabilities | (562) | (863) | |||||||||
| Cash provided by operating activities | 2,638 | 3,210 | |||||||||
| Cash flows — investing activities: | |||||||||||
| Capital expenditures, including nuclear fuel purchases and LTSA prepayments | (1,916) | (1,648) | |||||||||
| Energy Harbor acquisition (net of cash acquired) | — | (3,065) | |||||||||
| Proceeds from sales of nuclear decommissioning trust fund securities | 4,120 | 1,573 | |||||||||
| Investments in nuclear decommissioning trust fund securities | (4,138) | (1,590) | |||||||||
| Proceeds from sales of environmental allowances | 57 | 147 | |||||||||
| Purchases of environmental allowances | (511) | (511) | |||||||||
| Insurance proceeds for recovery of damaged property, plant and equipment | 198 | 3 | |||||||||
| Proceeds from sale of property, plant and equipment, including nuclear fuel | 21 | 137 | |||||||||
| Other, net | 7 | (5) | |||||||||
| Cash used in investing activities | (2,162) | (4,959) | |||||||||
| Cash flows — financing activities: | |||||||||||
| Issuances of debt | 424 | 2,200 | |||||||||
| Repayments/repurchases of debt | (764) | (2,269) | |||||||||
| Net borrowings under accounts receivable financing | 475 | 750 | |||||||||
| Borrowings under Revolving Credit Facility | 150 | 50 | |||||||||
| Repayments under Revolving Credit Facility | (150) | (50) | |||||||||
| Borrowings under Commodity-Linked Facility | 987 | 1,802 | |||||||||
| Repayments under Commodity-Linked Facility | (987) | (1,802) | |||||||||
| Debt issuance costs | (2) | (32) | |||||||||
| Stock repurchases | (776) | (1,021) | |||||||||
| Dividends paid to common stockholders | (229) | (230) | |||||||||
| Dividends paid to preferred stockholders | (117) | (98) | |||||||||
| Dividends paid to noncontrolling interest holders | — | (15) |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars) | |||||||||||
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| Tax withholding on stock based compensation | (51) | (11) | |||||||||
| Principal payment on forward repurchase obligation | (41) | — | |||||||||
| TRA Repurchase and tender offer — return of capital | — | (122) | |||||||||
| Other, net | 21 | (2) | |||||||||
| Cash used in financing activities | (1,060) | (850) | |||||||||
| Net change in cash, cash equivalents and restricted cash | (584) | (2,599) | |||||||||
| Cash, cash equivalents and restricted cash — beginning balance | 1,222 | 3,539 | |||||||||
| Cash, cash equivalents and restricted cash — ending balance | $ | 638 | $ | 940 |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (Millions of Dollars) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Preferred Stock | Common Stock | Treasury Stock | Additional Paid-In Capital | Accumulated Deficit | Accumulated Other Comprehensive Income | Total Stockholders' Equity | Noncontrolling Interest in Subsidiary | Total Equity | |||||||||||||||||||||||||||||||||||||||||||||
| Balances at December 31, 2024 | $ | 2,476 | $ | 5 | $ | (5,912) | $ | 9,435 | $ | (454) | $ | 20 | $ | 5,570 | $ | 13 | $ | 5,583 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (336) | — | — | — | (336) | — | (336) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans (a) | — | — | — | (27) | — | — | (27) | — | (27) | ||||||||||||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | (268) | — | (268) | — | (268) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (75) | — | (75) | — | (75) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (38) | — | (38) | — | (38) | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (1) | — | — | (1) | — | (1) | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at March 31, 2025 | $ | 2,476 | $ | 5 | $ | (6,248) | $ | 9,407 | $ | (835) | $ | 20 | $ | 4,825 | $ | 13 | $ | 4,838 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (237) | — | — | — | (237) | — | (237) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 43 | — | — | 43 | — | 43 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 327 | — | 327 | — | 327 | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (77) | — | (77) | — | (77) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (58) | — | (58) | — | (58) | ||||||||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income | — | — | — | — | — | (1) | (1) | — | (1) | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at June 30, 2025 | $ | 2,476 | $ | 5 | $ | (6,485) | $ | 9,450 | $ | (642) | $ | 19 | $ | 4,823 | $ | 13 | $ | 4,836 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (190) | — | — | — | (190) | — | (190) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 42 | — | — | 42 | — | 42 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 652 | — | 652 | — | 652 | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (79) | — | (79) | — | (79) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (39) | — | (39) | — | (39) | ||||||||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income | — | — | — | — | — | 1 | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (1) | 1 | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at September 30, 2025 | $ | 2,476 | $ | 5 | $ | (6,675) | $ | 9,491 | $ | (107) | $ | 20 | $ | 5,210 | $ | 13 | $ | 5,223 |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (CONTINUED) (Unaudited) (Millions of Dollars) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Preferred Stock | Common Stock | Treasury Stock | Additional Paid-In Capital | Accumulated Deficit | Accumulated Other Comprehensive Income | Total Stockholders' Equity | Noncontrolling Interest in Subsidiary | Total Equity | |||||||||||||||||||||||||||||||||||||||||||||
| Balances at December 31, 2023 | $ | 2,476 | $ | 5 | $ | (4,662) | $ | 10,095 | $ | (2,613) | $ | 6 | $ | 5,307 | $ | 15 | $ | 5,322 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (285) | — | — | — | (285) | — | (285) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans (a) | — | — | — | 35 | — | — | 35 | — | 35 | ||||||||||||||||||||||||||||||||||||||||||||
| Equity issued in subsidiary to acquire Energy Harbor (b) | — | — | — | 747 | — | — | 747 | 1,560 | 2,307 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | (35) | — | (35) | 53 | 18 | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (77) | — | (77) | — | (77) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (37) | — | (37) | — | (37) | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | 1 | — | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at March 31, 2024 | $ | 2,476 | $ | 5 | $ | (4,947) | $ | 10,878 | $ | (2,762) | $ | 6 | $ | 5,656 | $ | 1,628 | $ | 7,284 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (331) | — | — | — | (331) | — | (331) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 40 | — | — | 40 | — | 40 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 365 | — | 365 | 102 | 467 | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (77) | — | (77) | — | (77) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (59) | — | (59) | — | (59) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends to noncontrolling interest | — | — | — | — | — | — | — | (15) | (15) | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (1) | — | — | (1) | (1) | (2) | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at June 30, 2024 | $ | 2,476 | $ | 5 | $ | (5,278) | $ | 10,917 | $ | (2,533) | $ | 6 | $ | 5,593 | $ | 1,714 | $ | 7,307 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (406) | — | — | — | (406) | — | (406) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 28 | — | — | 28 | — | 28 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 1,888 | — | 1,888 | (51) | 1,837 | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (76) | — | (76) | — | (76) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (39) | — | (39) | — | (39) | ||||||||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income | — | — | — | — | — | 1 | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Modification of noncontrolling interest to redeemable noncontrolling interest (b) | — | — | — | (1,539) | — | — | (1,539) | (1,659) | (3,198) | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (10) | 1 | — | (9) | 10 | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at September 30, 2024 | $ | 2,476 | $ | 5 | $ | (5,684) | $ | 9,396 | $ | (759) | $ | 7 | $ | 5,441 | $ | 14 | $ | 5,455 |
See Notes to Condensed Consolidated Financial Statements
(a)Includes cash payments to cover tax withholding obligations upon the vesting of stock-based incentive compensation plans of $50 million and $12 million for the three months ended March 31, 2025 and 2024, respectively.
(b)See Note 2 for additional information regarding activity associated with noncontrolling interest.
See Notes to Condensed Consolidated Financial Statements
VISTRA CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
**1.**BUSINESS, SIGNIFICANT ACCOUNTING POLICIES, SIGNIFICANT EVENTS, AND RECENT DEVELOPMENTS
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 16 for additional information.
Significant Accounting Policies
Basis of Presentation
The condensed 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 2024 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. The condensed consolidated financial information herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. 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.
Recent Accounting Pronouncements
Improvements to Income Tax Disclosures
In December 2023, the FASB issued Accounting Standards Update (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. The amendments only apply to income tax disclosures and we do not expect adoption to have a material impact on our 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.
Significant Events
Moss Landing 300 Incident
On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site (the Moss Landing Incident) that resulted in ceasing operations at all facilities at the Moss Landing complex until the fire was contained. No injuries occurred due to the fire or the Company's response. The Moss Landing complex includes two other battery facilities and a gas plant. The gas plant returned to service in February 2025, but the two other battery facilities remain offline as we continue to investigate the cause of the fire. We expect the Moss Landing 350 MW battery to return to service in late 2025 or early 2026. There is less certainty about the return to service regarding the Moss Landing 100 MW battery. We will know more after the investigation of the cause of the Moss Landing Incident is complete. As of September 30, 2025, the net book value of the Moss Landing 100 facility was approximately $165 million.
As a result of the damage caused by the Moss Landing Incident, during the three months ended March 31, 2025, we wrote-off the net book value of Moss Landing 300 of approximately $400 million to depreciation expense and moved the asset to the Asset Closure segment as we have no plans to return the Moss Landing 300 facility to operations (see Notes 6 and 16 for additional information).
In July 2025, we entered into an Administrative Settlement Agreement and Order on Consent (ASAOC) with the EPA related to the Moss Landing 300 site. Under the ASAOC, we are required to perform specific battery removal and remediation activities, including battery removal and disposal, building demolition, and air and water monitoring. We estimate the total cost of these activities to be approximately $110 million. We have incurred expenses of approximately $29 million on ASAOC activities through September 30, 2025. As of September 30, 2025, our accrual for estimated future costs for the ASAOC activities is approximately $81 million, of which, $68 million is reflected in other current liabilities and $13 million is reflected in other noncurrent liabilities and deferred credits in the condensed consolidated balance sheets. This estimate assumes the ASAOC activities will be completed by the end of 2026. Aside from battery removal and disposal, our estimate does not reflect costs associated with removal of other hazardous waste that could be identified as the demolition progresses as we are unable to estimate such costs until sampling of waste material is complete. We will account for any adjustments to the accrual as a change in estimate in the period new information becomes available.
Additional impacts from the Moss Landing Incident include loss of revenue from the facilities being offline and may include litigation costs and penalties under contracts. See Note 13 for additional information.
We have filed insurance claims against applicable insurance policies with combined business interruption and property loss limits of $500 million, net of deductibles. As of March 31, 2025, the insurance receivable asset related to expenses we believe are probable of recovery from property damage insurance was $425 million, recorded as offsets to the expenses incurred in other noncurrent assets in the condensed consolidated balance sheets. See Insurance Recoveries for additional information.
Martin Lake Unit 1 Incident
On November 27, 2024, we experienced a fire at Unit 1 of our Martin Lake facility in ERCOT (the Martin Lake Incident), an 815 MW unit. We wrote-off the unit's net book value of less than $1 million to depreciation expense in December 2024. We expect the unit to return to service in late 2025 or early 2026. We estimate total cash capital expenditures required to restore the unit to service will be approximately $355 million, of which approximately $155 million in cash capital expenditures have been incurred as of September 30, 2025.
We expect to recover a majority of the expenditures associated with the Martin Lake Incident through property damage insurance and to receive additional business interruption proceeds. During the nine months ended September 30, 2025, we recognized property damage insurance recoveries of $104 million, of which $24 million was recorded as an offset to operating costs incurred to restore the unit to service, and $80 million was recorded as a gain in other income, net in the condensed consolidated statements of operations. See Insurance Recoveries for additional information.
Insurance Recoveries
The following table summarizes the expenses recorded, net of property damage insurance recoveries, related to the Moss Landing Incident and Martin Lake Incident during the three and nine months ended September 30, 2025.
| Three Months Ended September 30, 2025 | Nine Months Ended September 30, 2025 | ||||||||||||||||||||||||||||||||||
| Moss Landing Incident | Martin Lake Incident | Total | Moss Landing Incident | Martin Lake Incident | Total | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Write-off of net book value of facility to depreciation and amortization | $ | — | $ | — | $ | — | $ | 400 | $ | — | $ | 400 | |||||||||||||||||||||||
| Operating costs incurred to restore Martin Lake to service | — | 4 | 4 | — | 24 | 24 | |||||||||||||||||||||||||||||
| Incurred and estimated cost of ASAOC activities to operating costs (a) | — | — | — | 102 | — | 102 | |||||||||||||||||||||||||||||
| Total incident expense | $ | — | $ | 4 | $ | 4 | $ | 502 | $ | 24 | $ | 526 | |||||||||||||||||||||||
| Property damage insurance receivable as of the beginning of the period (b) | $ | 304 | $ | 20 | $ | 324 | $ | — | $ | — | $ | — | |||||||||||||||||||||||
| Recovery of incident expense recorded to insurance receivable | — | 4 | 4 | 425 | 24 | 449 | |||||||||||||||||||||||||||||
| Insurance recovery gain recorded in other non-operating income, net | — | — | — | — | 80 | 80 | |||||||||||||||||||||||||||||
| Insurance proceeds received | (7) | (20) | (27) | (128) | (100) | (228) | |||||||||||||||||||||||||||||
| Property damage insurance receivable as of the end of the period (b) | $ | 297 | $ | 4 | $ | 301 | $ | 297 | $ | 4 | $ | 301 | |||||||||||||||||||||||
| Total incident expense, net of property damage insurance recoveries | $ | — | $ | — | $ | — | $ | 77 | $ | — | $ | 77 |
(a)Total estimated costs of ASAOC activities is expected to be approximately $110 million, of which $102 million was recorded in operating costs in the condensed consolidated statements of operations. Amounts above exclude $8 million of estimated demolition and battery removal costs reclassified from the Moss Landing 300 ARO to other current liabilities during the three months ended March 31, 2025.
(b)Property damage insurance receivable is included in other noncurrent assets on the condensed consolidated balance sheets.
The following table summarizes the business interruption insurance recoveries related to the Moss Landing Incident and Martin Lake Incident during the three and nine months ended September 30, 2025.
| Three Months Ended September 30, 2025 | Nine Months Ended September 30, 2025 | |||||||||||||||||||||||||||||||||||||
| Moss Landing Incident | Martin Lake Incident | Total | Moss Landing Incident | Martin Lake Incident | Total | |||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||
| Business interruption insurance proceeds received (a) | $ | 1 | $ | — | $ | 1 | $ | 22 | $ | — | $ | 22 |
(a)Business interruption insurance proceeds is included in operating revenues in the condensed consolidated statements of operations.
We expect to receive additional property damage and business interruption insurance proceeds related to the Martin Lake Incident and additional business interruption insurance proceeds related to the Moss Landing Incident which are not included in the property damage insurance receivable as of the period ended September 30, 2025. These additional proceeds will be recorded as income in the period they are realized.
Recent Developments
Acquisition of Natural Gas Generation Facilities
In October 2025, Vistra Operations completed the acquisition of subsidiaries of Lotus Infrastructure Partners (Lotus). See Note 2 for additional information.
Debt, Credit Facilities, and Financings
Vistra Operations Commodity-Linked Revolving Credit Facility — In October 2025, Vistra Operations amended the Commodity-Linked Facility to, among other things, (i) extend the maturity date to September 30, 2026, and (ii) modify the calculation of the borrowing base. See Note 9 for additional information. In October 2025, Vistra Operations borrowed $100 million under the Commodity-Linked Facility.
Vistra Operations Senior Secured Notes — In October 2025, Vistra Operations issued $2.0 billion aggregate principal amount of senior secured notes, consisting of $750 million aggregate principal amount of 4.300% senior secured notes due 2028, $500 million aggregate principal amount of 4.600% senior secured notes due 2030, and $750 million principal amount of 5.250% senior secured notes due 2035 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. See Note 9 for additional information.
Vistra Operations Senior Unsecured Notes — In October 2025, Vistra Operations used proceeds from the October 2025 issuance of Vistra Operations Senior Secured Notes discussed above to redeem the $1.0 billion outstanding principal amount of 5.500% Senior Unsecured Notes due 2026.
Share Repurchase Program
In October 2025, the Board authorized an incremental amount of $1.0 billion for repurchases under our share repurchase program.
2. ACQUISITIONS
Acquisition of Natural Gas Generation Facilities
On October 22, 2025 (Acquisition Date), pursuant to a purchase and sale agreement dated May 15, 2025, Vistra Operations acquired 100% of the membership interests of subsidiaries of Lotus (the Acquisition). The Acquisition resulted in the addition of seven natural gas generation facilities totaling 2,600 MW in Delaware and Pennsylvania (PJM), Rhode Island (ISO-NE), New York (NYISO), and California (CAISO), further geographically diversifying Vistra's natural gas fleet.
The aggregate purchase price consisted of a base purchase price of $1.9 billion, subject to certain customary adjustments, including the acquired companies' working capital, cash, indebtedness, and certain other adjustments. Vistra Operations funded the Acquisition with a combination of cash and the assumption of the acquired companies' indebtedness, which consisted of a senior secured credit facility, including an existing term loan with approximately $800 million principal outstanding, which reduced the cash consideration payable at closing. Cash consideration payable at closing, excluding adjustments for the acquired companies' working capital, cash, and certain other adjustments, was $1.1 billion.
The Acquisition will be 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 Acquisition Date. Vistra will provide the amounts recognized as of the Acquisition Date for the major classes of assets acquired and liabilities assumed, as well as the supplemental pro forma revenues and net income of Vistra as if the Acquisition had been completed on January 1, 2024, in Vistra's Annual Report on Form 10‑K for the period ended December 31, 2025.
Energy Harbor Business Combination
On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023, (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 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 condensed 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 condensed 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.
Provisional fair value measurements were made for acquired assets and liabilities in the first quarter of 2024 and adjustments to those measurements were made through March 1, 2025 (the end of the measurement period). The final fair values assigned to assets acquired and liabilities assumed are as follows:
| Fair Value as of March 1, 2024 | Measurement Period Adjustments | ||||||||||
| (in millions) | |||||||||||
| Cash and cash equivalents | $ | 35 | $ | 5 | |||||||
| Trade accounts receivables, inventories, prepaid expenses and other current assets | 540 | 2 | |||||||||
| 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 | 62 | 54 | |||||||||
| Total identifiable assets acquired | 8,847 | 62 | |||||||||
| Trade accounts payable and other current liabilities | 318 | 55 | |||||||||
| 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 | 20 | 8 | |||||||||
| Total identifiable liabilities assumed | 3,667 | (5) | |||||||||
| Identifiable net assets acquired | 5,180 | 67 | |||||||||
| Goodwill (f) | 227 | (67) | |||||||||
| 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.
The following unaudited pro forma financial information for the three and nine months ended September 30, 2024 assumes that the Energy Harbor Merger occurred on January 1, 2024. 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, 2024, 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.
| Three Months Ended September 30, 2024 | Nine Months Ended September 30, 2024 | ||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Revenues | $ | 6,288 | $ | 13,911 | |||||||||||||||||||
| Net income | $ | 1,837 | $ | 2,411 | |||||||||||||||||||
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 $1 million and $25 million for the three and nine months ended September 30, 2024, respectively, and are classified as selling, general, and administrative expenses in the condensed 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 represented 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, 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.
3. REVENUE
Revenue Disaggregation
The following tables disaggregate our revenue by major source:
| Three Months Ended September 30, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Consolidated | |||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers: | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail energy charge in ERCOT | $ | 2,698 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 2,698 | |||||||||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest | 1,054 | — | — | — | — | — | 1,054 | ||||||||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 112 | 543 | 28 | — | — | 683 | ||||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (a) | — | — | 79 | — | — | — | 79 | ||||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 100 | 101 | 61 | — | 2 | 264 | ||||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 3,752 | 212 | 723 | 89 | — | 2 | 4,778 | ||||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||
| Transferable PTC revenues (b) | — | 145 | — | — | — | — | 145 | ||||||||||||||||||||||||||||||||||||||||
| Hedging revenues — realized | 396 | (422) | (108) | 26 | — | — | (108) | ||||||||||||||||||||||||||||||||||||||||
| Hedging revenues — unrealized | (43) | 251 | (97) | 50 | 1 | — | 162 | ||||||||||||||||||||||||||||||||||||||||
| Business interruption insurance proceeds | — | — | — | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||
| Intangible amortization and other revenues | — | — | (7) | — | — | — | (7) | ||||||||||||||||||||||||||||||||||||||||
| Intersegment sales (c) | 34 | 1,613 | 1,239 | — | — | (2,886) | — | ||||||||||||||||||||||||||||||||||||||||
| Total other revenues | 387 | 1,587 | 1,027 | 76 | 2 | (2,886) | 193 | ||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 4,139 | $ | 1,799 | $ | 1,750 | $ | 165 | $ | 2 | $ | (2,884) | $ | 4,971 |
(a)Includes $270 million of capacity sold offset by $191 million of capacity purchased in each ISO/RTO in the East segment. If the net capacity purchased or sold in an ISO/RTO results in a net capacity purchase, the net purchase is included in fuel, purchased power costs, and delivery fees.
(b)Represents transferable PTCs generated from qualifying nuclear and solar assets during the period.
(c)The Texas segment includes $28 million of intersegment unrealized net losses and the East segment includes $4 million of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.
| Three Months Ended September 30, 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 | $ | 2,500 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 2,500 | |||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest (a) | 1,051 | — | — | — | — | — | 1,051 | ||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 122 | 347 | 50 | 1 | — | 520 | ||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (b) | — | — | 18 | — | — | — | 18 | ||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 93 | 100 | 48 | 10 | 1 | 252 | ||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 3,551 | 215 | 465 | 98 | 11 | 1 | 4,341 | ||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||
| Transferable PTC revenue | — | 4 | — | — | — | — | 4 | ||||||||||||||||||||||||||||||||||
| Hedging revenues — realized | 373 | (382) | (52) | 35 | (3) | — | (29) | ||||||||||||||||||||||||||||||||||
| Hedging revenues — unrealized | 308 | 1,253 | 299 | 98 | 2 | — | 1,960 | ||||||||||||||||||||||||||||||||||
| Intangible amortization and other revenues | 1 | — | (1) | — | 1 | 11 | 12 | ||||||||||||||||||||||||||||||||||
| Intersegment sales (c) | 18 | 3,154 | 1,142 | 1 | — | (4,315) | — | ||||||||||||||||||||||||||||||||||
| Total other revenues | 700 | 4,029 | 1,388 | 134 | — | (4,304) | 1,947 | ||||||||||||||||||||||||||||||||||
| Total revenues | $ | 4,251 | $ | 4,244 | $ | 1,853 | $ | 232 | $ | 11 | $ | (4,303) | $ | 6,288 |
(a)Includes revenues associated with operations acquired in the Energy Harbor Merger.
(b)Represents net capacity sold in each ISO/RTO. The East segment includes $30 million of capacity sold offset by $12 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in the condensed consolidated statement of operations includes capacity purchased of $44 million offset by $28 million of capacity sold within the East segment.
(c)The Texas, East, and West segment includes $1.527 billion, $55 million, and $1 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.
| Nine Months Ended September 30, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Consolidated | |||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers: | |||||||||||||||||||||||||||||||||||||||||
| Retail energy charge in ERCOT | $ | 6,890 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 6,890 | |||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest | 2,886 | — | — | — | — | — | 2,886 | ||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 231 | 1,725 | 75 | — | — | 2,031 | ||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (a) | — | — | 129 | — | — | — | 129 | ||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 338 | 323 | 176 | 5 | 3 | 845 | ||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 9,776 | 569 | 2,177 | 251 | 5 | 3 | 12,781 | ||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||
| Transferable PTC revenues (b) | — | 151 | — | — | — | — | 151 | ||||||||||||||||||||||||||||||||||
| Hedging revenues — realized | 1,040 | (458) | (158) | 90 | — | — | 514 | ||||||||||||||||||||||||||||||||||
| Hedging revenues — unrealized | (59) | 198 | (446) | 4 | 2 | — | (301) | ||||||||||||||||||||||||||||||||||
| Business interruption insurance proceeds | — | — | — | — | 22 | — | 22 | ||||||||||||||||||||||||||||||||||
| Intangible amortization and other revenues | — | (2) | (11) | — | — | — | (13) | ||||||||||||||||||||||||||||||||||
| Intersegment sales (c) | 82 | 3,339 | 3,048 | 2 | (3) | (6,468) | — | ||||||||||||||||||||||||||||||||||
| Total other revenues | 1,063 | 3,228 | 2,433 | 96 | 21 | (6,468) | 373 | ||||||||||||||||||||||||||||||||||
| Total revenues | $ | 10,839 | $ | 3,797 | $ | 4,610 | $ | 347 | $ | 26 | $ | (6,465) | $ | 13,154 |
(a)Includes $477 million of capacity sold offset by $348 million of capacity purchased in each ISO/RTO in the East segment. If the net capacity purchased or sold in an ISO/RTO results in a net capacity purchase, the net purchase is included in fuel, purchased power costs, and delivery fees.
(b)Represents transferable PTCs generated from qualifying nuclear and solar assets during the period.
(c)The Texas and East segments include $93 million and $103 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.
| Nine Months Ended September 30, 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 | $ | 6,241 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 6,241 | |||||||||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest (a) | 2,705 | — | — | — | — | — | 2,705 | ||||||||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 278 | 844 | 164 | 4 | — | 1,290 | ||||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (b) | — | — | 54 | — | — | — | 54 | ||||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 325 | 312 | 147 | 24 | 1 | 809 | ||||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 8,946 | 603 | 1,210 | 311 | 28 | 1 | 11,099 | ||||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||
| Transferable PTC revenues | — | 9 | — | — | — | — | 9 | ||||||||||||||||||||||||||||||||||||||||
| Hedging revenues — realized | 927 | (524) | 35 | 68 | (8) | — | 498 | ||||||||||||||||||||||||||||||||||||||||
| Hedging revenues — unrealized | (3) | 893 | 356 | 317 | 8 | — | 1,571 | ||||||||||||||||||||||||||||||||||||||||
| Intangible amortization and other revenues | — | — | (3) | — | 1 | 12 | 10 | ||||||||||||||||||||||||||||||||||||||||
| Intersegment sales (c) | 43 | 3,943 | 2,643 | 5 | — | (6,634) | — | ||||||||||||||||||||||||||||||||||||||||
| Total other revenues | 967 | 4,321 | 3,031 | 390 | 1 | (6,622) | 2,088 | ||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 9,913 | $ | 4,924 | $ | 4,241 | $ | 701 | $ | 29 | $ | (6,621) | $ | 13,187 |
(a)Includes seven months of revenue associated with operations acquired in the Energy Harbor Merger.
(b)Represents net capacity sold in each ISO/RTO. The East segment includes $94 million of capacity sold offset by $40 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the condensed consolidated statement of operations includes capacity purchased of $88 million offset by $47 million of capacity sold within the East segment.
(c)The Texas and West segments include $605 million and $3 million, respectively, of intersegment unrealized net gains and the East segment includes $123 million of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.
Performance Obligations
As of September 30, 2025, 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 when the performance obligations to provide capacity to the relevant ISOs/RTOs or counterparties are fulfilled.
| Balance of 2025 | 2026 | 2027 | 2028 | 2029 | 2030 and Thereafter | Total | |||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||
| Remaining performance obligations | $ | 370 | $ | 1,647 | $ | 882 | $ | 122 | $ | 62 | $ | 548 | $ | 3,631 |
Trade Accounts Receivable
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Wholesale and retail trade accounts receivable | $ | 2,431 | $ | 2,061 | |||||||
| Allowance for credit losses | (104) | (79) | |||||||||
| Trade accounts receivable — net | $ | 2,327 | $ | 1,982 | |||||||
| Trade accounts receivable from contracts with customers — net | $ | 1,776 | $ | 1,514 | |||||||
| Other trade accounts receivable — net | 551 | 468 | |||||||||
| Trade accounts receivable — net | $ | 2,327 | $ | 1,982 |
Gross trade accounts receivable as of September 30, 2025 and December 31, 2024 include unbilled retail revenues of $924 million and $802 million, respectively.
Allowance for Credit Losses on Accounts Receivable
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2025 | 2024 | ||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Allowance for credit losses on accounts receivable at beginning of period | $ | 79 | $ | 61 | |||||||||||||||||||
| Increase for bad debt expense | 152 | 132 | |||||||||||||||||||||
| Decrease for account write-offs | (127) | (105) | |||||||||||||||||||||
| Allowance for credit losses on accounts receivable at end of period | $ | 104 | $ | 88 |
4. GOVERNMENT ASSISTANCE
Inflation Reduction Act of 2022 (IRA)
In August 2022, the U.S. enacted the IRA, which introduced various energy tax credits. Among these, it acknowledged the importance of existing carbon-free nuclear power by establishing a nuclear Production Tax Credit under section 45U (nuclear PTC), a solar PTC, new technology-neutral ITCs and PTCs that apply to various different clean energy technologies, and a new stand-alone battery storage investment tax credit. The nuclear PTC provides a federal tax credit of up to $15 per MWh, subject to phase out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively. The nuclear PTC applies 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.
Transferable PTCs
In each of the three and nine months ended September 30, 2025, we recognized transferable nuclear PTC revenues of $145 million. Nuclear PTC revenues are an estimate based on projected annual gross receipts generated from qualifying nuclear production in 2025 and reflect our determination that we will meet the prevailing wage requirements necessary to earn the five times multiplier. The amount recognized in the nine months ended September 30, 2025 reflects a pro-rata allocation of the forecasted annual nuclear PTC revenue based on actual qualifying nuclear production during the period. Our computation of forecasted gross receipts includes merchant energy revenues and capacity revenues (for our PJM nuclear units only) at each nuclear unit and excludes any hedges and ancillary revenue. Treasury regulations may further define the scope of the legislation in many important respects, including interpretive guidance on the definition of gross receipts for the nuclear PTC. Any interpretive guidance on the definition of gross receipts that differs from the interpretation used in our estimate could result in a material change to PTC revenues recorded in 2024 and 2025 and would be reflected as a change in estimate in the period in which the guidance is received.
Sales of Transferable PTCs
During 2025, we sold $490 million transferable nuclear PTCs recognized from qualifying 2024 nuclear generation, of which $200 million was sold in January 2025, $90 million was sold in May and June 2025, and $200 million was sold in September 2025. Cash proceeds of $278 million and $469 million were received during the three and nine months ended September 30, 2025, respectively.
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
The components of our income tax expense are as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net income before income taxes | $ | 856 | $ | 2,392 | $ | 815 | $ | 3,016 | |||||||||||||||
| Income tax expense | $ | (204) | $ | (555) | $ | (104) | $ | (694) | |||||||||||||||
| Effective tax rate | 23.8 | % | 23.2 | % | 12.8 | % | 23.0 | % |
We evaluate and update our annual effective income tax rate on an interim basis based on current and forecasted earnings and tax laws. The mix and timing of our actual earnings compared to annual projections, as well as the amount of pre-tax earnings in comparison to the required discrete items, can cause interim effective tax rate fluctuations.
For the three months ended September 30, 2025, the effective rate of 23.8% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes. For the nine months ended September 30, 2025, the effective tax rate of 12.8% was lower than the U.S. federal statutory rate of 21% due primarily to permanent differences recorded discretely related to stock-based compensation, partially offset by state income taxes.
For the three months ended September 30, 2024, the effective tax rate of 23.2% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes. For the nine months ended September 30, 2024, the effective tax rate of 23.0% was higher than the U.S. federal statutory rate of 21% due primarily to the impact of state income taxes offset by discrete tax benefits related to stock-based compensation.
OBBBA and CAMT
In July 2025, the legislation known as the OBBBA was signed into law and we have accounted for the effects in our consolidated financial statements. Key changes include the immediate expensing of domestic research and development costs, the reinstatement of 100% bonus depreciation, and increases in the limitation of interest deductibility. Certain provisions of the OBBBA will change the timing of cash tax payments in the current fiscal year and future year periods, however the legislation did not have a material impact on our consolidated financial statements. We do not expect Vistra to be subject to the corporate alternative minimum tax (CAMT) in the 2025 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 forecasted OBBBA impacts into account when forecasting cash taxes.
6. PROPERTY, PLANT, AND EQUIPMENT
Our property, plant, and equipment consist of our power generation assets, related mining assets, land, information systems hardware, capitalized corporate office lease space, and other leasehold improvements. Land and construction work in progress are not depreciated.
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Power generation and structures and office and other equipment | $ | 22,510 | $ | 22,943 | |||||||
| Land | 614 | 603 | |||||||||
| Construction work in progress (a) | 1,969 | 1,060 | |||||||||
| Finance lease right-of-use assets | 186 | 186 | |||||||||
| Nuclear fuel | 2,054 | 1,843 | |||||||||
| Property, plant and equipment — gross | 27,333 | 26,635 | |||||||||
| Less accumulated depreciation | (8,918) | (8,020) | |||||||||
| Less finance lease right-of-use assets accumulated amortization | (39) | (33) | |||||||||
| Less accumulated amortization on nuclear fuel | (651) | (409) | |||||||||
| Property, plant and equipment — net | $ | 17,725 | $ | 18,173 |
(a)During the three and nine months ended September 30, 2025, we recognized impairments of $5 million and $73 million, respectively, related to development projects we have no plans to complete.
Depreciation and amortization of property, plant, and equipment (including the classification in the condensed consolidated statements of operations) consisted of the following:
| Property, Plant, and Equipment | Condensed Consolidated Statements of Operations | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Power generation and structures and office and other equipment | Depreciation and amortization | $ | 417 | $ | 419 | $ | 1,393 | $ | 1,173 | ||||||||||||||||||||
| Finance lease right-of-use assets | Depreciation and amortization | 2 | 2 | 6 | 6 | ||||||||||||||||||||||||
| Nuclear fuel | Fuel, purchased power costs, and delivery fees | 129 | 123 | 366 | 269 | ||||||||||||||||||||||||
| Total property, plant, and equipment expense | $ | 548 | $ | 544 | $ | 1,765 | $ | 1,448 |
Retirement of Generation Facilities
Below are our operating facilities that have an announced retirement date. Operating results for generation facilities with defined retirement dates are included in our Asset Closure segment in the calendar year following the year in which the retirement occurs or is expected to occur. The Moss Landing 300 facility was transferred to the Asset Closure segment during the first quarter of 2025 as we do not plan to return the asset to operations. See Note 1 for additional information.
| Facility | Location | ISO/RTO | Fuel Type | Net Capacity (MW) | Expected or Actual 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 | 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 middle of 2028 | East | ||||||||||||||||||||||||||||||||
| Newton | Newton, IL | MISO | Coal | 615 | By the end of 2027 | East | ||||||||||||||||||||||||||||||||
| Total | 4,578 |
(a)Expected retirement dates may change if economic or other conditions dictate.
The Company intends to repower Coleto Creek and Miami Fort as gas-fueled facilities upon their retirements as coal-fueled facilities. We are currently evaluating the feasibility of converting the other coal-fueled facilities with expected retirement dates in 2027 to gas-fueled facilities.
7. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
Goodwill
As of September 30, 2025 and December 31, 2024, the carrying value of goodwill totaled $2.810 billion and $2.807 billion, respectively.
| Retail Segment | Texas Segment | ||||||||||||||||||||||
| Retail Reporting Unit (a) | Texas Reporting Unit | Goodwill Pending Allocation | Total Goodwill | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Balance at December 31, 2024 | $ | 2,461 | $ | 122 | $ | 224 | $ | 2,807 | |||||||||||||||
| Measurement period adjustment recorded in connection with the Energy Harbor Merger (b) | 227 | — | (224) | 3 | |||||||||||||||||||
| Balance at September 30, 2025 | $ | 2,688 | $ | 122 | $ | — | $ | 2,810 |
(a)Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight line basis.
(b)Includes the allocation of goodwill attributable to the Energy Harbor acquisition to the retail reporting unit (see Note 2 for additional information).
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are comprised of the following:
| September 30, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||
| Identifiable Intangible Asset | Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | ||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||
| Retail customer relationships | $ | 2,173 | $ | 2,044 | $ | 129 | $ | 2,173 | $ | 1,977 | $ | 196 | ||||||||||||||||||||||||||
| Software and other technology-related assets | 566 | 347 | 219 | 601 | 293 | 308 | ||||||||||||||||||||||||||||||||
| Retail and wholesale contracts | 503 | 410 | 93 | 503 | 353 | 150 | ||||||||||||||||||||||||||||||||
| Long-term service agreements | 18 | 6 | 12 | 18 | 5 | 13 | ||||||||||||||||||||||||||||||||
| Other identifiable intangible assets (a) | 319 | 16 | 303 | 218 | 13 | 205 | ||||||||||||||||||||||||||||||||
| Total identifiable intangible assets subject to amortization | $ | 3,579 | $ | 2,823 | 756 | $ | 3,513 | $ | 2,641 | 872 | ||||||||||||||||||||||||||||
| Retail trade names (not subject to amortization) | 1,341 | 1,341 | ||||||||||||||||||||||||||||||||||||
| Total identifiable intangible assets | $ | 2,097 | $ | 2,213 |
(a)Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).
Identifiable intangible liabilities are comprised of the following:
| Identifiable Intangible Liability | September 30, 2025 | December 31, 2024 | ||||||||||||
| (in millions) | ||||||||||||||
| Long-term service agreements | $ | 101 | $ | 108 | ||||||||||
| Wholesale power and fuel purchase contracts | 40 | 47 | ||||||||||||
| Total identifiable intangible liabilities | $ | 141 | $ | 155 |
Amortization of finite-lived identifiable intangible assets and liabilities (including the classification in the condensed consolidated statements of operations) consisted of the following:
| Identifiable Intangible Assets/Liabilities | Condensed Consolidated Statements of Operations | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Retail customer relationships | Depreciation and amortization | $ | 23 | $ | 29 | $ | 68 | $ | 82 | ||||||||||||||||||||
| Software and other technology-related assets | Depreciation and amortization | 17 | 15 | 53 | 43 | ||||||||||||||||||||||||
| Retail and wholesale contracts | Operating revenues/Fuel, purchased power costs, and delivery fees | (2) | (5) | (6) | (9) | ||||||||||||||||||||||||
| Other identifiable intangible assets (a) | Fuel, purchased power costs, and delivery fees/Depreciation and amortization | 127 | 131 | 350 | 327 | ||||||||||||||||||||||||
| Total intangible asset expense, net | $ | 165 | $ | 170 | $ | 465 | $ | 443 |
(a)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 condensed 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.
Estimated Amortization of Identifiable Intangible Assets
As of September 30, 2025, 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 | $ | 218 | ||||||
| 2026 | $ | 168 | ||||||
| 2027 | $ | 73 | ||||||
| 2028 | $ | 53 | ||||||
| 2029 | $ | 37 |
8. COLLATERAL FINANCING AGREEMENT WITH AFFILIATE
In 2023, Vistra Operations entered into a 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.
As of September 30, 2025 and December 31, 2024, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $450 million and $435 million, respectively, and is reported in the condensed consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate. See Note 8 to the Financial Statements in our 2024 Form 10-K for additional information.
9. DEBT, CREDIT FACILITIES, AND FINANCINGS
Debt, credit facilities and financing obligations on the condensed consolidated balance sheets consisted of the following:
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Long-term debt, including amounts due currently: | |||||||||||
| Project-level debt | $ | 1,488 | $ | 1,064 | |||||||
| Vistra Operations debt | 14,642 | 15,405 | |||||||||
| Long -term debt before unamortized premiums, discounts and issuance costs | 16,130 | 16,469 | |||||||||
| Unamortized premiums, discounts and issuance costs | (142) | (171) | |||||||||
| Long-term debt including amounts due currently | $ | 15,988 | $ | 16,298 | |||||||
| Accounts receivable financing | $ | 1,225 | $ | 750 | |||||||
| Forward repurchase obligation | $ | 1,314 | $ | 1,335 | |||||||
Long-Term Debt
The Company's long-term debt obligations, including amounts due currently, consisted of the following:
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 | $ | 2,456 | $ | 2,475 | |||||||
| BCOP Credit Facility, Bridge Loans (a) | 367 | 367 | |||||||||
| BCOP Credit Facility, Construction / Term Loans (a) | 424 | — | |||||||||
| Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 | 697 | 697 | |||||||||
| Vistra Operations Senior Secured Notes: | |||||||||||
| 5.125% Senior Secured Notes, due May 13, 2025 | — | 744 | |||||||||
| 5.050% Senior Secured Notes, due December 30, 2026 | 500 | 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 | 500 | |||||||||
| 5.700% Senior Secured Notes, due December 30, 2034 | 750 | 750 | |||||||||
| Total Vistra Operations Senior Secured Notes | 4,400 | 5,144 | |||||||||
| Energy Harbor Revenue Bonds: | |||||||||||
| 3.375% Revenue Bond, due August 1, 2029 | 100 | 100 | |||||||||
| 4.750% Revenue Bonds, due June 1, 2033 and July 1, 2033 | 285 | 285 | |||||||||
| 3.750% Revenue Bond, due October 1, 2047 | 46 | 46 | |||||||||
| Total Energy Harbor Revenue Bonds | 431 | 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 1, 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 | 1,000 | |||||||||
| Total Vistra Operations Senior Unsecured Notes | 7,300 | 7,300 | |||||||||
| Other: | |||||||||||
| Equipment Financing Agreements | 55 | 55 | |||||||||
| Total other long-term debt | 55 | 55 | |||||||||
| Unamortized debt premiums, discounts and issuance costs | (142) | (171) | |||||||||
| Total long-term debt including amounts due currently | 15,988 | 16,298 | |||||||||
| Less amounts due currently (b) | (231) | (880) | |||||||||
| Total long-term debt less amounts due currently | $ | 15,757 | $ | 15,418 |
(a)See Credit Facilities table below for details of the BCOP Credit Facility maturities.
(b)Excludes 5.500% Senior Unsecured Notes due September 1, 2026 as amounts were refinanced on a long-term basis using a portion of the net proceeds from the October 2025 issuance of $2.0 billion of Vistra Operations senior secured notes. See Vistra Operations Senior Secured Notes below.
Long-Term Debt Maturities
Long-term debt maturities as of September 30, 2025 are as follows:
| September 30, 2025 | |||||
| (in millions) | |||||
| Remainder of 2025 | $ | 208 | |||
| 2026 (a) | 2,014 | ||||
| 2027 | 3,432 | ||||
| 2028 | 32 | ||||
| 2029 | 2,283 | ||||
| Thereafter | 8,161 | ||||
| Unamortized premiums, discounts and debt issuance costs | (142) | ||||
| Total long-term debt, including amounts due currently | $ | 15,988 |
(a)Includes 5.500% Senior Unsecured Notes due September 1, 2026 that were refinanced on a long-term basis using a portion of the net proceeds from the October 2025 issuance of $2.0 billion of Vistra Operations senior secured notes. See Vistra Operations Senior Secured Notes below.
Credit Facilities
Our credit facilities and related available capacity as of September 30, 2025 are presented below.
| September 30, 2025 | ||||||||||||||||||||||||||||||||||||||
| 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 | $ | — | $ | 981 | $ | 2,459 | |||||||||||||||||||||||||||||
| Term Loan B-3 Facility | December 20, 2030 | 2,456 | 2,456 | — | — | |||||||||||||||||||||||||||||||||
| Total Vistra Operations Credit Facilities | 5,896 | 2,456 | 981 | 2,459 | ||||||||||||||||||||||||||||||||||
| Vistra Operations Commodity-Linked Facility | October 1, 2025 (a) | 1,750 | — | — | 644 | |||||||||||||||||||||||||||||||||
| Total Vistra Operations debt | $ | 7,646 | $ | 2,456 | $ | 981 | $ | 3,103 | ||||||||||||||||||||||||||||||
| Project-level debt: | ||||||||||||||||||||||||||||||||||||||
| Bridge Loans | November 1, 2025 (b) / December 3, 2026 | $ | 367 | $ | 367 | $ | — | $ | — | |||||||||||||||||||||||||||||
| Construction / Term Loans | (c) | 424 | 424 | — | — | |||||||||||||||||||||||||||||||||
| BCOP Credit Facility (d) | 791 | 791 | — | — | ||||||||||||||||||||||||||||||||||
| Vistra Zero Term Loan B Facility (d) | April 30, 2031 | 697 | 697 | — | — | |||||||||||||||||||||||||||||||||
| Total project-level debt | $ | 1,488 | $ | 1,488 | $ | — | $ | — | ||||||||||||||||||||||||||||||
| Total credit facilities | $ | 9,134 | $ | 3,944 | $ | 981 | $ | 3,103 | ||||||||||||||||||||||||||||||
(a)In October 2025, Vistra Operations amended the Commodity-Linked Facility to, among other things, extend the maturity date to September 30, 2026.
(b)In October 2025, the maturity date on $106 million of Bridge Loans was extended to January 30, 2026. See further discussion in BCOP Project-level Credit Facilities discussion below.
(c)Consists of $120 million of Term Loans due December 3, 2029, $88 million of Construction Term Loans with a maturity date of November 1, 2025 that converted to Term Loans on October 30, 2025 with a maturity date of December 3, 2029, and $216 million of Construction Loans with a maturity date of December 3, 2026 that are expected to convert to Term Loans on or before December 3, 2026. See further discussion in BCOP Project-level Credit Facilities discussion below.
(d)Vistra Zero Operating's and BCOP's obligations under the Vistra Zero Credit Agreement and the BCOP Credit Agreement, respectively, are guaranteed by subsidiaries of Vistra Zero Operating and BCOP, respectively, but are otherwise non-recourse to Vistra Operations and its other subsidiaries.
Vistra Operations Credit Facilities
As of September 30, 2025, the Vistra Operations Credit Facilities have aggregate commitments of up to $5.896 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 (including aggregate revolving letter of credit commitments) of up to $3.440 billion, (Revolving Credit Facility), and (ii) term loans of $2.456 billion (Term Loan B-3 Facility).
Revolving Credit Facility — The Revolving Credit Facility is used for general corporate purposes. Under the Vistra Operations Credit Agreement, (i) 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 ranges from 1.25% to 2.00%, and (ii) the fee payable on any undrawn amounts with respect to the Revolving Credit Facility that ranges from 17.5 basis points to 35.0 basis points. Interest periods for Term SOFR borrowings are for 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 is 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 September 30, 2025, 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 1.75%, and the weighted average interest rates before taking into consideration interest rate swaps (see Note 10 for additional information) on outstanding borrowings of $2.456 billion was 5.91% as of September 30, 2025. Interest periods for Term SOFR loans are for 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 (or, during a collateral suspension period, a consolidated total 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.
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 September 30, 2025, Vistra Operations can distribute approximately $10.9 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 $350 million and $515 million for the three months ended September 30, 2025 and 2024, respectively, and $1.275 billion and $1.505 billion for the nine months ended September 30, 2025 and 2024, 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 September 30, 2025, all of the restricted net assets of Vistra Operations may be distributed to Parent.
Vistra Operations Commodity-Linked Revolving Credit Facility
As of September 30, 2025, the Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) totaled $1.750 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. In October 2025, Vistra Operations amended the Commodity-Linked Facility to, among other things, extend the maturity date to September 30, 2026. As of September 30, 2025, the borrowing base of $644 million is lower than the facility limit which represents the aggregate commitments of $1.750 billion.
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 based on either the Term SOFR or a daily simple SOFR rate plus (i) a spread that ranges from 1.25% to 2.00%, and (ii) sustainability pricing adjustments based on certain sustainability-linked targets and thresholds. Interest periods for Term SOFR borrowings are for 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 September 30, 2025, 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. As of September 30, 2025, there were no outstanding borrowings under the Commodity-Linked Facility.
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) bridge loans of $367 million for the Oak Hill and Pulaski projects (Bridge Loans) and (ii) construction/term loan commitments of $528 million (Construction/Term Loan Facility) and debt service reserve letter of credit facility commitments of $29 million (Debt Service Reserve, and, collectively with the Bridge Loans and the Construction/Term Loan Facility, the BCOP Credit Facility).
As of September 30, 2025, the Bridge Loans for Oak Hill and Pulaski totaled $106 million and $261 million, respectively, and will mature in November 2025 and December 2026, respectively, subject to the terms of the BCOP Credit Agreement. In October 2025, the maturity date on $106 million of Oak Hill Bridge Loans was extended to January 30, 2026. Interest is paid on the Bridge Loans in arrears based on the applicable Term SOFR elected in the borrowing notice plus a fixed spread of 1.625% per annum, and the weighted average interest rate on outstanding borrowings was 5.648% as of September 30, 2025. Repayment of the Bridge Loans is guaranteed by Vistra as the beneficiary of the underlying investment tax credits to be generated by the projects.
The Construction/Term Loan Facility consists of (i) term loans supporting the Baldwin and Coffeen projects and (ii) construction loans to fund the Oak Hill and Pulaski project costs during construction that will convert to term loans once each project reaches its commercial operation date and term conversion date. On April 1, 2025, BCOP funded $75 million and $46 million of term loans for Baldwin and Coffeen, respectively, that will mature in December 2029, and issued $7 million in letters of credit under the Debt Service Reserve facility to support the Baldwin and Coffeen term loans. On May 20, 2025, BCOP funded $88 million of construction loans for Oak Hill with a maturity date in November 2025 and, subject to meeting certain conditions, will convert to a term loan maturing in December 2029. In October 2025, the $88 million of construction loans converted to a term loan. In July and August 2025, BCOP funded $216 million total of construction loans for Pulaski that will mature in December 2026 and, subject to meeting certain conditions, will convert to a term loan maturing in December 2029. Interest on the construction/term loans will be paid in arrears based on the applicable Term SOFR elected in the borrowing notice plus fixed spreads of 1.875% per annum for construction loans and 2.000% per annum for term loans, and the weighted average interest rate on outstanding construction/term loans was 6.03% as of September 30, 2025. Beginning on the term funding or term conversion date, the term loans will amortize over a 20-year period and debt amortization and interest payments will be funded with cash flows from the underlying project. Fees on the issued debt service reserve letters of credit will be paid in arrears at 2.000% per annum. Commitment fees on the undrawn loan commitments and unissued letter of credit commitments will be paid quarterly in arrears at a fixed percentage of the loan's fixed spread.
Vistra Zero Project-level Credit Agreement
In March 2024, Vistra Zero Operating 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 Operating 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 Operating's obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operating but are otherwise non-recourse to Vistra Operations and its other subsidiaries.
Interest on the Term Loan B Facility is based on Term SOFR plus 2.00% per annum. Interest periods for Term SOFR loans are for 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 6.16% as of September 30, 2025.
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 June 2025, 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 do not have stated expiration dates and are used for general corporate purposes. As of September 30, 2025, $1.301 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 September 30, 2025, the total capacity was $500 million and $500 million of letters of credit were outstanding under the Alternative LOC Facilities. In October 2025, the Alternative LOC Facilities were amended to increase the commitment cap to a total of $800 million. The commitments under the Alternative LOC Facilities terminate in December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities.
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 May 2025, the $744 million outstanding principal amount of the 5.125% Senior Secured Notes due May 2025 were repaid at maturity.
In October 2025, Vistra Operations issued $2.0 billion aggregate principal amount of senior secured notes, consisting of $750 million aggregate principal amount of 4.300% senior secured notes due 2028 (4.300% Senior Secured Notes), $500 million aggregate principal amount of 4.600% senior secured notes due 2030 (4.600% Senior Secured Notes), and $750 million principal amount of 5.250% senior secured notes due 2035 (5.250% 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 of each year, beginning April 15, 2026. Net proceeds from the offering, together with cash on hand, were used (i) to support refinancing activities for outstanding indebtedness (see Vistra Operations Senior Unsecured Notes below), (ii) for general corporate purposes, including to fund a portion of the Acquisition (see Note 2 for additional information), and (iii) to pay fees and expenses related to the offering.
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 October 2025, Vistra Operations used a portion of the proceeds from the October 2025 issuance of Vistra Operations Senior Secured Notes discussed above to redeem the $1.0 billion outstanding principal amount of 5.500% Senior Unsecured Notes due 2026.
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 June 2025, the Receivables Facility was amended to add Dynegy Energy Services Mid-Atlantic, LLC. In July 2025, the Receivables Facility was amended to increase the purchase limit from $1.0 billion to $1.1 billion and extend the term of the Receivables Facility to July 2026.
In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Dynegy Energy Services Mid-Atlantic, LLC, 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 condensed consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in the condensed 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 September 30, 2025, outstanding borrowings under the Receivables Facility totaled $1.1 billion and were supported by $1.764 billion of RecCo gross receivables. As of December 31, 2024, there were $750 million 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 2025, the Repurchase Facility was renewed until July 2026 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 represents 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.
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.
As of September 30, 2025, outstanding borrowings under the Repurchase Facility totaled $125 million. There were no outstanding borrowings under the Repurchase Facility as of December 31, 2024.
Forward Repurchase Obligation
In accordance with the amended UPAs, on December 31, 2024, Vistra closed the acquisition of the Vistra Vision minority interest 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. In June 2025, Vistra made scheduled installment payments to reduce the forward repurchase obligation by $80 million, including $41 million of principal and $39 million of interest. Principal and interest payments remaining due to Nuveen are as follows:
| September 30, 2025 | |||||
| (in millions) | |||||
| Remainder of 2025 | $ | 701 | |||
| 2026 | 669 | ||||
| Thereafter | — | ||||
| Total scheduled payments under the UPAs | $ | 1,370 |
The present value of the remaining payment obligations to Nuveen discounted at 6% totaled $1.314 billion and $1.335 billion at September 30, 2025 and December 31, 2024, respectively, and is included in forward repurchase obligation due currently and forward obligation, less amounts due currently in the condensed consolidated balance sheet.
Interest Expense and Related Charges
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Interest expense | $ | 272 | $ | 244 | $ | 819 | $ | 702 | |||||||||||||||
| Unrealized mark-to-market net losses on interest rate swaps | 10 | 84 | 84 | 26 | |||||||||||||||||||
| Amortization of debt issuance costs, discounts, and premiums | 11 | 9 | 33 | 25 | |||||||||||||||||||
| Debt extinguishment gain | — | — | — | (6) | |||||||||||||||||||
| Capitalized interest | (30) | (20) | (86) | (52) | |||||||||||||||||||
| Other | 23 | 15 | 58 | 48 | |||||||||||||||||||
| Total interest expense and related charges | $ | 286 | $ | 332 | $ | 908 | $ | 743 |
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 5.21% and 5.52% as of September 30, 2025 and 2024, respectively.
10. 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.
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 condensed 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 condensed consolidated statements of operations in interest expense and related charges.
As of September 30, 2025, Vistra has entered into the following interest rate swaps:
| Notional Amount | Expiration Date | Rate Range (d) | ||||||||||||||||||||||||
| (in millions, except percentages) | ||||||||||||||||||||||||||
| Swapped to fixed (a) | $3,000 | July 2026 | 2.89 | % | - | 2.97% | ||||||||||||||||||||
| Swapped to variable (a) | $700 | July 2026 | 1.44 | % | - | 1.49% | ||||||||||||||||||||
| Swapped to fixed (b) | $2,300 | December 2030 | 3.20 | % | - | 3.76% | ||||||||||||||||||||
| Swapped to fixed (c) | $416 | March, July and October 2045 | 3.95 | % | - | 4.09% |
(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. These swaps will hedge our exposure on $2.3 billion of floating rate debt from August 2026 through December 2030.
(c)In March 2025, May 2025 and July 2025, BCOP entered into interest rate swaps with notional amounts of approximately $108 million, $70 million and $238 million, respectively. These swaps are effective as of April 2025, October 2025 and October 2026, and will expire in March 2045, October 2045 and July 2045, respectively. These swaps are intended to hedge BCOP's exposure on approximately $416 million of floating rate Construction/Term Loan Facility commitments issued under the BCOP Credit Agreement. (see Note 9 for additional information).
(d)The rate ranges reflect the fixed leg of each swap at the applicable Term SOFR rate.
Effect of Derivative Instruments on the Condensed 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 condensed consolidated balance sheets to the net value on a contract basis, after taking into consideration netting arrangements with counterparties and cash collateral recorded.
| September 30, 2025 | |||||||||||||||||||||||||||||
| Derivative Contract Assets | Derivative Contract Liabilities | ||||||||||||||||||||||||||||
| Commodity Contracts | Interest Rate Swaps | Commodity Contracts | Interest Rate Swaps | Total | |||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Current assets | $ | 2,615 | $ | 18 | $ | 1 | $ | — | $ | 2,634 | |||||||||||||||||||
| Noncurrent assets | 579 | 2 | 23 | — | 604 | ||||||||||||||||||||||||
| Current liabilities | — | — | (3,596) | (14) | (3,610) | ||||||||||||||||||||||||
| Noncurrent liabilities | (4) | — | (1,362) | (22) | (1,388) | ||||||||||||||||||||||||
| Net assets (liabilities) | $ | 3,190 | $ | 20 | $ | (4,934) | $ | (36) | $ | (1,760) | |||||||||||||||||||
| Offsetting instruments (a) | (2,553) | (12) | 2,553 | 12 | — | ||||||||||||||||||||||||
| Financial collateral (received) pledged (b) | (11) | — | 516 | — | 505 | ||||||||||||||||||||||||
| Net amounts | $ | 626 | $ | 8 | $ | (1,865) | $ | (24) | $ | (1,255) |
| 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) |
(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.
Effect of Derivative Instruments in the Condensed Consolidated Statements of Operations
The following table summarizes the location and amount of unrealized gains and losses from our derivative instruments recorded in the condensed consolidated statements of operations for the three and nine months ended September 30, 2025 and 2024:
| Derivative (condensed consolidated statements of operations presentation) | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Reversals of previously recognized unrealized (gain) loss on derivative instruments: | |||||||||||||||||||||||
| Commodity contracts unrealized (gain) loss in operating revenues (a) | $ | 735 | $ | 754 | $ | 878 | $ | 1,172 | |||||||||||||||
| Commodity contracts unrealized (gain) loss in fuel, purchased power costs, and delivery fees (a) | 11 | 23 | 3 | 178 | |||||||||||||||||||
| Interest rate swaps unrealized (gain) loss in interest expense and related charges | (5) | (11) | (16) | (33) | |||||||||||||||||||
| Total reversals of previously recognized unrealized (gain) loss on derivative instruments | $ | 741 | $ | 766 | $ | 865 | $ | 1,317 | |||||||||||||||
| Unrealized net gain (loss) from changes in fair value on derivative instruments: | |||||||||||||||||||||||
| Commodity contracts unrealized gain (loss) in operating revenues | $ | (573) | $ | 1,206 | $ | (1,179) | $ | 399 | |||||||||||||||
| Commodity contracts unrealized gain (loss) in fuel, purchased power costs, and delivery fees | 11 | (128) | (69) | (24) | |||||||||||||||||||
| Interest rate swaps unrealized gain (loss) in interest expense and related charges | (5) | (73) | (68) | 7 | |||||||||||||||||||
| Total unrealized net gain (loss) from change in fair value on derivative instruments | $ | (567) | $ | 1,005 | $ | (1,316) | $ | 382 | |||||||||||||||
| Net gain (loss) on derivative instruments | $ | 174 | $ | 1,771 | $ | (451) | $ | 1,699 |
____________
(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 that did not financially settle but were realized at the contract's notional and price. The realized effects of these items are included in operating revenues and fuel, purchased power costs, and delivery fees.
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes by commodity, excluding our normal purchases and normal sales (NPNS) derivatives that are not recorded at fair value:
| September 30, 2025 | December 31, 2024 | |||||||||||||||||||
| Derivative type | Notional Volume | Unit of Measure | ||||||||||||||||||
| Natural gas | 4,017 | 4,568 | Million MMBtu | |||||||||||||||||
| Electricity | 881,426 | 796,982 | GWh | |||||||||||||||||
| Financial transmission rights / Congestion revenue rights | 254,680 | 248,742 | GWh | |||||||||||||||||
| Coal | 29 | 27 | Million U.S. tons | |||||||||||||||||
| Fuel oil | 3 | 2 | Million gallons | |||||||||||||||||
| Emissions | 33 | 28 | Million U.S. tons | |||||||||||||||||
| Renewable energy certificates | 29 | 31 | Million certificates | |||||||||||||||||
| Interest rate swaps – variable/fixed | $ | 5,716 | $ | 5,300 | Million U.S. dollars | |||||||||||||||
| Interest rate swaps – fixed/variable | $ | 700 | $ | 700 | Million U.S. dollars |
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:
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Fair value of derivative contract liabilities (a) | $ | (1,432) | $ | (1,587) | |||||||
| Offsetting fair value under netting arrangements (b) | 597 | 724 | |||||||||
| Cash collateral and letters of credit | 293 | 471 | |||||||||
| Liquidity exposure | $ | (542) | $ | (392) |
____________
(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 that increase 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) credit enhancements (such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits) that are required in the event of a material downgrade in their credit rating.
| September 30, 2025 | ||||||||
| (in millions, except percentages) | ||||||||
| Credit risk exposure to derivative contract counterparties: | ||||||||
| Gross exposure | $ | 3,653 | ||||||
| Net exposure (a) | $ | 740 | ||||||
| Largest net exposure from any single counterparty (a) | $ | 302 | ||||||
| Percent of credit risk exposure to derivative contract counterparties related to banking and financial sector: | ||||||||
| Gross exposure | 73 | % | ||||||
| Net exposure (a) | 13 | % |
____________
(a)Exposure after taking into effect netting arrangements, setoff provisions, and collateral.
11. 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.
-
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:
| September 30, 2025 | December 31, 2024 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Reclass (a) | Total | Level 1 | Level 2 | Level 3 | Reclass (a) | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts (b) | $ | 2,047 | $ | 416 | $ | 727 | $ | 28 | $ | 3,218 | $ | 1,923 | $ | 462 | $ | 841 | $ | 5 | $ | 3,231 | |||||||||||||||||||||||||||||||||||||||
| Interest rate swaps (b) | — | 20 | — | — | 20 | — | 96 | — | — | 96 | |||||||||||||||||||||||||||||||||||||||||||||||||
| NDTs – equity securities (c)(d) | 1,769 | — | — | 1,769 | 1,560 | — | — | 1,560 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| NDTs – debt securities (c)(e) | 110 | 1,877 | — | 1,987 | 83 | 1,976 | — | 2,059 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Sub-total | $ | 3,926 | $ | 2,313 | $ | 727 | $ | 28 | 6,994 | $ | 3,566 | $ | 2,534 | $ | 841 | $ | 5 | 6,946 | |||||||||||||||||||||||||||||||||||||||||
| Assets measured at net asset value (f): | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NDTs – equity securities (c)(d)(f) | 850 | 821 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NDTs - debt securities (c)(e)(f) | 323 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 8,167 | $ | 7,767 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts (b) | $ | 2,574 | $ | 686 | $ | 1,674 | $ | 28 | $ | 4,962 | $ | 2,118 | $ | 975 | $ | 1,593 | $ | 5 | $ | 4,691 | |||||||||||||||||||||||||||||||||||||||
| Interest rate swaps (b) | — | 36 | — | — | 36 | — | 27 | — | — | 27 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | $ | 2,574 | $ | 722 | $ | 1,674 | $ | 28 | $ | 4,998 | $ | 2,118 | $ | 1,002 | $ | 1,593 | $ | 5 | $ | 4,718 |
(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 condensed consolidated balance sheets.
(b)See Note 10 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 condensed 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 September 30, 2025.
(d)The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 and Russell 3000 Indices for U.S. equity investments and the MSCI EAFE and MSCI All Country World ex-US Indices 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 4.14% and 3.99% as of September 30, 2025 and December 31, 2024, respectively, and an average maturity of eight years and seven years as of September 30, 2025 and December 31, 2024, respectively. NDT debt securities held as of September 30, 2025 mature as follows: $783 million in one to five years, $1.074 billion in five to 10 years and $453 million after 10 years.
(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 condensed consolidated balance sheets.
The following tables present the fair value of Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of September 30, 2025 and December 31, 2024:
| September 30, 2025 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Contract Type (a) | Assets | Liabilities | Total, Net | Valuation Technique | Significant Unobservable Input | Range (b) | Average (b) | |||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Electricity purchases and sales | $ | 467 | $ | (1,457) | $ | (990) | Income Approach | Hourly price curve shape (c) | $— | to | $95 | $48 | ||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Illiquid delivery periods for hub power prices (d) | $25 | to | $135 | $80 | ||||||||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Market Heat Rates (d) | $25 | to | $135 | $80 | ||||||||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Options | 3 | (173) | (170) | Option Pricing Model | Natural gas to power correlation (e) | 15% | to | 100% | 58% | |||||||||||||||||||||||||||||||||||||||||
| Power and natural gas volatility (e) | 5% | to | 970% | 488% | ||||||||||||||||||||||||||||||||||||||||||||||
| Financial transmission rights/Congestion revenue rights | 231 | (33) | 198 | Market Approach (f) | Illiquid price differences between settlement points (g) | $(12) | to | $25 | $6.5 | |||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 16 | (11) | 5 | Income Approach | Natural gas basis (h) | $(1) | to | $14 | $6 | |||||||||||||||||||||||||||||||||||||||||
| MMBtu | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Illiquid delivery periods (i) | $3 | to | $5 | $4 | ||||||||||||||||||||||||||||||||||||||||||||||
| MMBtu | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other (j) | 10 | — | 10 | |||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 727 | $ | (1,674) | $ | (947) |
| 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) |
(a)(i) Electricity purchase and sales contracts include 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.
The following table presents the changes in fair value of Level 3 assets and liabilities:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net liability balance at beginning of period | $ | (884) | $ | (1,104) | $ | (752) | $ | (1,044) | |||||||||||||||
| Total unrealized valuation gains (losses) | (299) | 482 | (443) | 194 | |||||||||||||||||||
| Purchases, issuances and settlements (a): | |||||||||||||||||||||||
| Purchases | 94 | 62 | 226 | 193 | |||||||||||||||||||
| Issuances | (4) | (7) | (10) | (24) | |||||||||||||||||||
| Settlements | (12) | 57 | (103) | 196 | |||||||||||||||||||
| Transfers into Level 3 (b) | 1 | 5 | (4) | (15) | |||||||||||||||||||
| Transfers out of Level 3 (b) | 157 | (12) | 139 | (4) | |||||||||||||||||||
| Net liabilities assumed in connection with the Energy Harbor Merger | — | — | — | (13) | |||||||||||||||||||
| Net change | (63) | 587 | (195) | 527 | |||||||||||||||||||
| Net liability balance at end of period | $ | (947) | $ | (517) | $ | (947) | $ | (517) | |||||||||||||||
| Unrealized valuation losses relating to instruments held at end of period | $ | (340) | $ | 361 | $ | (519) | $ | (114) |
(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 three months ended September 30, 2025, 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 nine months ended September 30, 2025, 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, natural gas and coal derivatives where forward pricing inputs have become observable. For the three months ended September 30, 2024, transfers into Level 3 primarily consist of natural gas derivatives where forward pricing inputs have become unobservable. For the nine months ended September 30, 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 coal and natural gas 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
| September 30, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||
| 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 | $ | 2,421 | $ | 2,461 | $ | 2,435 | $ | 2,478 | |||||||||||||||||||||||
| BCOP Credit Facility | Level 3 | 774 | 790 | 344 | 367 | |||||||||||||||||||||||||||
| Vistra Zero Term Loan B Facility | Level 2 | 687 | 687 | 685 | 697 | |||||||||||||||||||||||||||
| Vistra Operations Senior Notes | Level 2 | 11,636 | 11,954 | 12,366 | 12,428 | |||||||||||||||||||||||||||
| Energy Harbor Revenue Bonds | Level 2 | 415 | 437 | 414 | 431 | |||||||||||||||||||||||||||
| Equipment Financing Agreements | Level 3 | 55 | 55 | 54 | 53 | |||||||||||||||||||||||||||
| Forward Repurchase Obligation | Level 3 | 1,314 | 1,314 | 1,335 | 1,335 | |||||||||||||||||||||||||||
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.
12. 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 nine months ended September 30, 2025 and 2024:
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | ||||||||||||||||||||||||||||||||||
| Nuclear Plant Decommissioning | Land Reclamation, Coal Ash, and Other | Total | Nuclear Plant Decommissioning | Land Reclamation, Coal Ash, and Other | Total | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Liability at beginning of period | $ | 3,240 | $ | 838 | $ | 4,078 | $ | 1,742 | $ | 796 | $ | 2,538 | |||||||||||||||||||||||
| Additions: | |||||||||||||||||||||||||||||||||||
| Accretion (a) | 114 | 30 | 144 | 95 | 31 | 126 | |||||||||||||||||||||||||||||
| Adjustment for change in estimates (b) | 11 | (26) | (15) | — | 18 | 18 | |||||||||||||||||||||||||||||
| Adjustment for obligations assumed through acquisition | — | — | — | 1,368 | — | 1,368 | |||||||||||||||||||||||||||||
| Reductions: | |||||||||||||||||||||||||||||||||||
| Payments | — | (61) | (61) | — | (64) | (64) | |||||||||||||||||||||||||||||
| Liability at end of period | 3,365 | 781 | 4,146 | 3,205 | 781 | 3,986 | |||||||||||||||||||||||||||||
| Less amounts due currently | — | (202) | (202) | — | (102) | (102) | |||||||||||||||||||||||||||||
| Noncurrent liability at end of period | $ | 3,365 | $ | 579 | $ | 3,944 | $ | 3,205 | $ | 679 | $ | 3,884 |
(a)For the nine months ended September 30, 2025 and 2024, nuclear plant decommissioning accretion includes $70 million and $53 million, respectively, of accretion expense recognized in operating costs in the condensed consolidated statements of operations and $44 million and $42 million, respectively, reflected as a change in regulatory liability in the condensed consolidated balance sheets.
(b)There is a corresponding non-cash change in property, plant, and equipment related to land, reclamation, coal ash, and other ARO adjustments of $(14) million and $7 million for the nine months ended September 30, 2025 and 2024, respectively.
Nuclear Decommissioning AROs
AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and 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.
As of September 30, 2025, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $1.852 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.543 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $691 million recorded to the condensed 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. During the three months ended September 30, 2025, we completed a nuclear decommissioning study for the Comanche Peak plant resulting in an increase to our nuclear plant decommissioning ARO of $11 million.
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 condensed 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 condensed 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 condensed consolidated statement of operations.
13. COMMITMENTS AND CONTINGENCIES
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 September 30, 2025, we had outstanding letters of credit totaling $2.782 billion as follows:
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$2.400 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;
-
$257 million to support battery and solar development projects;
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$25 million to support executory contracts and insurance agreements;
-
$86 million to support our REP financial requirements with the PUCT; and
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$14 million for other credit support requirements.
Surety Bonds
As of September 30, 2025, we had outstanding surety bonds totaling $995 million 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. In August 2025, the Seventh Circuit Court vacated the district court's order certifying the class and remanded the case back to the district court for further consideration consistent with the Seventh Circuit Court's decision. The parties reached an agreement in principle to settle the case that is subject to court approval and, in November 2025, the plaintiffs filed a motion to begin the process of obtaining that approval. The settlement is for an amount that is not material to the consolidated financial statements.
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 Energy Trust 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 five-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.
Dorrell Antitrust Litigation — In July 2025, an antitrust lawsuit was filed in the U.S. District Court for the District of Maryland against Human Resources Consultants, LLC, Accelerant Technologies, Constellation Energy Corporation and 25 other companies, including Vistra Corp. and Luminant Generation Company, LLC. Plaintiffs allege that since at least May 2003, the defendants exchanged confidential compensation information and conspired to fix and suppress compensation of all persons employed in nuclear power generation in violation of federal antitrust law. In October 2025, motions to dismiss these claims were filed. We believe we have strong defenses to this lawsuit and intend to defend against this case vigorously.
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, wrongful death, and insurance lawsuits related to Winter Storm Uri have been filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. These cases were transferred to a single multi-district litigation (MDL) pretrial judge for all pretrial proceedings. 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 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. The plaintiffs have petitioned the Texas Supreme Court to review that decision and filed their opening brief in September 2025. 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. Several lawsuits have been filed in California federal and state courts against Vistra, LG Energy Solution (LG), and others, as a result of this incident.
The EPA is providing control and oversight of clean up and remediation efforts on the site. In July 2025, we entered into an ASAOC with the EPA that requires us to perform certain activities, which primarily include battery removal and disposal, building demolition, and air and water monitoring at the Moss Landing 300 site. By entering into this ASAOC, we will conduct these activities under the EPA's oversight. As of September 30, 2025, we have incurred and accrued estimated expenses related to these activities of approximately $110 million for the recovery effort. See Note 1 for additional information.
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 administration's 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. In addition to that Order, in April 2025, President Trump issued a series of additional executive orders on energy and deregulation priorities for his administration. We will monitor implementation and any agency actions related to those and other executive orders.
Greenhouse Gas Emissions (GHG)
In May 2023, the EPA released a proposal regulating power plant 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. 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. 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. Oral argument on the merits of the legal challenges to the rule was held in December 2024 before the D.C. Circuit Court. The D.C. Circuit has granted the EPA's motion for an abeyance of the case and status reports are due at 90-day intervals. In June 2025, the EPA published a proposed repeal of GHG emission standards for fossil fuel-fired electric generation units, which could moot this case if the proposal is finalized and would result in no further federal regulation of GHGs at electric generating units. Additionally, in August 2025, the EPA issued a proposal that would repeal the agency's prior endangerment finding for all GHG emission standards for light-, medium-, and heavy-duty vehicles. The EPA also stated that for other rules that have relied on the endangerment finding it intends to initiate other rulemakings to address any overlapping issues.
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 eight-hour standard for ozone emissions during ozone season (May to September). As required under the Clean Air Act, 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, which the EPA disapproved in February 2023. 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 2025, the Fifth Circuit Court denied those petitions for review, but we and the State of Texas have filed petitions for rehearing of that decision. We do not expect any near-term impact to Texas sources from this decision because the EPA will need to undertake a new rulemaking to re-impose a FIP on Texas. In addition, based on policy recent pronouncements from the Trump administration, the new EPA is reevaluating its approach to these Good Neighbor SIPs in general.
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. 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.
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 April 2025, after previously denying the EPA's request for abeyance, the D.C. Circuit Court granted an abeyance of the case challenging the GNP FIP addressing interstate transport for all covered states. The Trump administration has stated that it is reevaluating this FIP.
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 SO2, 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. 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, and those cases are currently in abeyance. 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 SO2 limits on six facilities in Texas, including Martin Lake and Coleto Creek. Under the current proposal, compliance would be required within three years for Martin Lake and five 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. Based on several statements by the Trump administration and executive orders, we expect that the regional haze proposals will not be finalized as previously proposed by the Biden administration. In May 2025, the EPA issued a proposed rule for reasonable progress requirements that would (a) approve portions of Texas' first planning period regional haze SIP and (b) approve Texas' second planning period regional haze SIP. Under the EPA's proposals, no new controls would be required. We submitted comments in July 2025.
SO****2 Designations for Texas
In November 2016, the EPA finalized nonattainment designations for SO2 for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations required Texas to develop nonattainment plans for these areas. In February 2022, we and the TCEQ entered into an agreed order to reduce SO2 emissions at the Martin Lake plant, and the TCEQ submitted the agreed order to the EPA as a SIP revision to address the designation. We and the State of Texas filed legal challenges to the EPA's designations in the Fifth Circuit Court. In May 2025, the Fifth Circuit Court held that the EPA's designations were unlawful, granted the petitions for review, and remanded the designation back to the EPA. If the EPA revises the designation on remand from the Fifth Circuit Court, the matter would be resolved and no additional controls would be required at Martin Lake as a result of the designation. In addition, based on the designations, in August 2024, the EPA proposed a Finding of Failure to attain the SO2 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 on the SIP 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. In September 2025, the EPA issued a final rule withdrawing its Finding of Failure to Submit and Finding of Failure to Attain in light of the Fifth Circuit Court's May 2025 decision. Our petition remains in abeyance until November 2025 in the Fifth Circuit Court.
Effluent Limitation Guidelines (ELGs)
In October 2020, the EPA published a final rule that extends the compliance date for both flue gas desulfurization (FGD) and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the 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. 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 U.S. Court of Appeals for the Eighth Circuit granted the EPA's 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.
In October 2025, the EPA proposed additional revisions to the ELG rule, including extending certain compliance deadlines under the 2024 ELG rule. Those deadlines would generally apply to facilities that had not already utilized the retirement provisions in the 2020 ELG rule, which our company had utilized. In addition, the proposal also authorizes a process for states to extend the 2028 retirement deadline that was finalized as part of the 2020 ELG rule in the event market conditions would not support retirement of a facility. We are currently evaluating this proposal and the impact, if any, it might have on our announced plans to retire our remaining coal generation facilities in Illinois and Ohio by 2028 given that those facilities are under separate existing regulatory requirements to close by then.
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. In July 2025, the EPA, through a direct final rule and companion proposed rule, extended the deadlines for the Facility Evaluation Reports (FER) to 2027, groundwater monitoring to 2029, and closure requirements to 2030 for the CCRMU provisions of the rule. The direct final rule was withdrawn on September 4, 2025, but the companion proposal would similarly extend the CCRMU deadlines if finalized by the EPA. The EPA has stated that it plans to publish a proposed rule to revise the CCR rule by January 30, 2026, and a final rule by October 30, 2026. The case challenging the rule is in abeyance until December 2025.
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, in June 2021, we entered into an agreed interim consent order with the Illinois Attorney General and the Vermilion County State Attorney in which 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 condensed consolidated balance sheets (see Note 17 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 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. In 2025, we filed construction permit applications (or supplemented prior operating permit applications) to cover corrective action activities at 11 impoundments across our Illinois fleet.
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 it 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.
MISO 2015-2016 Planning Resource Auction
After the 2015-2016 planning resource auction (PRA) was conducted by MISO, in which Zone 4 separated from the rest of MISO, parties including Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as unjust and unreasonable. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA.
In July 2019, the FERC issued an order denying complaints. Upon appeal, in 2021, the D.C. Circuit Court of Appeals remanded the case back to the FERC on a narrow question. In June 2024, the FERC ordered the matter set for an evidentiary hearing (a trial before a FERC administrative law judge) to determine what the FERC cited as "disputed issues of material fact" and held the hearing in abeyance for the parties to engage in settlement discussions. In August 2025, FERC approved the settlement agreement that resolved all remaining allegations among the parties and Vistra made a settlement payment to MISO for an amount that is not material to the consolidated financial statements. This matter is now resolved.
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.
Nuclear Insurance Updates
In April 2025, we updated our nuclear accident decontamination and reactor damage stabilization insurance for our Beaver Valley, Davis-Besse and Perry facilities to $2.25 billion each and non-nuclear accident related property damage to $1.0 billion each. Prior to the April 2025 update, our nuclear accident decontamination and reactor damage stabilization insurance and non-nuclear accident related property damage for Beaver Valley, Davis-Besse and Perry was $1.5 billion each. Coverage is subject to a $10 million deductible per accident including natural hazards except for the Davis-Besse facility which has a $20 million deductible. Losses excluded or above such limits are self insured.
Also in April 2025, we updated our accidental outage insurance for our Beaver Valley and Perry facilities. Coverage provides for weekly payments per unit of up to $4.5 million (previously $2.5 million) for the first 52 weeks and up to $2.7 million (previously $1.5 million) for the remaining 21 weeks for non-nuclear and up to $3.6 million for a remaining 71 weeks (previously $2 million for a remaining 110 weeks) for nuclear accident property damage outages. The total maximum coverage is $291 million (previously $208 million) for non-nuclear accident property damage and $490 million (previously $350 million) for nuclear accident property damage outages.
14. EQUITY
Common Stock
Common 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 $0.2260 and $0.2195 for the three months ended September 30, 2025 and 2024, respectively, and $0.6745 and $0.6520 for the nine months ended September 30, 2025 and 2024, respectively.
In October 2025, the Board declared a quarterly dividend of $0.2270 per share of common stock that will be paid in December 2025.
Share Repurchase Program
As of September 30, 2025, the Board had authorized a $6.750 billion share repurchase program. In October 2025, the Board authorized an incremental amount of $1.0 billion for repurchases under the share repurchase program. Through October 31, 2025, 164,896,651 shares, at an average price of $33.81 per share, have been repurchased under this program. The following table provides information about our repurchases of common stock for the period between January 1, 2025 and October 31, 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) | |||||||||||||||||||||||
| Three Months Ended March 31, 2025 | 2,437,700 | $ | 137.66 | $ | 336 | ||||||||||||||||||
| Three Months Ended June 30, 2025 | 1,776,176 | 132.72 | 236 | ||||||||||||||||||||
| Three Months Ended September 30, 2025 (a) | 955,216 | 197.74 | 188 | ||||||||||||||||||||
| Nine Months Ended September 30, 2025 | 5,169,092 | $ | 147.07 | $ | 760 | $ | 1,249 | ||||||||||||||||
| October 1, 2025 through October 31, 2025 | 371,820 | 199.20 | 74 | ||||||||||||||||||||
| January 1, 2025 through October 31, 2025 | 5,540,912 | $ | 150.56 | $ | 834 | $ | 2,175 |
(a)Shares repurchased include 15,956 of unsettled shares for $3 million as of September 30, 2025.
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 | Shares Outstanding | Contractual Rates | Earliest Redemption Date (a) | Date at Which Dividend Rate Becomes Floating | Floating Annual Rates | |||||||||||||||||||||||||||||||||||||
| Series A | October 15, 2021 | 1,000,000 | 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 | 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 | 476,081 | 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)Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.
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 for the three and nine months ended September 30, 2025 and 2024.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| Preferred Stock Series | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||
| Series A Preferred Stock | $ | — | $ | — | $ | 40.000 | $ | 40.000 | ||||||||||||||||||
| Series B Preferred Stock | $ | — | $ | — | $ | 35.000 | $ | 35.000 | ||||||||||||||||||
| Series C Preferred Stock | $ | 44.375 | $ | 48.320 | $ | 88.750 | $ | 48.320 |
In July 2025, the Board declared a semi-annual dividend of $40.000 per share of Series A Preferred Stock that was paid in October 2025. In October 2025, the Board declared (i) a semi-annual dividend of $35.000 per share on Series B Preferred Stock that will be paid in December 2025, and (ii) a semi-annual dividend of $44.375 per share on Series C Preferred Stock that will be paid in January 2026.
15. 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.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (in millions, except share data) | |||||||||||||||||||||||
| Net income attributable to Vistra | $ | 652 | $ | 1,888 | $ | 711 | $ | 2,218 | |||||||||||||||
| Less cumulative dividends attributable to Series A Preferred Stock | (20) | (20) | (60) | (60) | |||||||||||||||||||
| Less cumulative dividends attributable to Series B Preferred Stock | (17) | (17) | (52) | (52) | |||||||||||||||||||
| Less cumulative dividends attributable to Series C Preferred Stock | (11) | (11) | (32) | (32) | |||||||||||||||||||
| Net income attributable to common stock — basic and diluted | 604 | 1,840 | $ | 567 | $ | 2,074 | |||||||||||||||||
| Weighted average shares of common stock outstanding: | |||||||||||||||||||||||
| Basic | 338,749,454 | 342,969,916 | 339,313,294 | 346,315,125 | |||||||||||||||||||
| Dilutive securities: Stock-based incentive compensation plan | 6,285,706 | 7,233,776 | 6,990,323 | 7,490,812 | |||||||||||||||||||
| Diluted | 345,035,160 | 350,203,692 | 346,303,617 | 353,805,937 | |||||||||||||||||||
| Net income per weighted average share of common stock outstanding: | |||||||||||||||||||||||
| Basic | $ | 1.78 | $ | 5.36 | $ | 1.67 | $ | 5.99 | |||||||||||||||
| Diluted | $ | 1.75 | $ | 5.25 | $ | 1.64 | $ | 5.86 |
Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 308 and 531 shares in the three months ended September 30, 2025 and 2024, respectively, and 103 and 11,210 shares for the nine months ended September 30, 2025 and 2024, respectively.
16. 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. Our Chief Executive Officer is our chief operating decision maker (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. 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 geographies.
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 segment. 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 Moss Landing 300 facility was transferred to the Asset Closure segment in the first quarter of 2025 as a result of the Moss Landing Incident.
The Asset Closure segment is engaged in the decommissioning and reclamation of retired generation facilities and mines. When facilities are transferred to the Asset Closure segment, prior period results are retrospectively adjusted for comparative purposes, provided the effects are material (see Note 6 for additional information). By separately reporting the Asset Closure segment, management gains improved insights into the performance and earnings potential of Vistra's ongoing operations while actively monitoring the cost associated with decommissioning and reclaiming retired generation facilities, including mines.
Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes, other expenses, and nuclear fuel cash capital expenditures 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 to the Financial Statements in our 2024 Form 10-K. 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 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.
| Three Months Ended September 30, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Asset Closure | Total Reportable Segments | Corporate and Other | Total | ||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues | $ | 4,139 | $ | 1,799 | $ | 1,750 | $ | 165 | $ | 2 | $ | 7,855 | $ | (2,884) | $ | 4,971 | |||||||||||||||||||||||||||||||
| Fuel, purchased power costs, and delivery fees (a) | (3,815) | (544) | (866) | (32) | — | (5,257) | 2,887 | (2,370) | |||||||||||||||||||||||||||||||||||||||
| Operating costs | (54) | (243) | (338) | (15) | (12) | (662) | 7 | (655) | |||||||||||||||||||||||||||||||||||||||
| Selling, general, and administrative expenses | (270) | (38) | (59) | (2) | (16) | (385) | (59) | (444) | |||||||||||||||||||||||||||||||||||||||
| Other segment items: | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | (23) | (160) | (244) | (14) | — | (441) | (19) | (460) | |||||||||||||||||||||||||||||||||||||||
| Interest expenses and related charges | (18) | 9 | 16 | 2 | (1) | 8 | (294) | (286) | |||||||||||||||||||||||||||||||||||||||
| Income tax expense | — | — | — | — | — | — | (204) | (204) | |||||||||||||||||||||||||||||||||||||||
| Other (b) | 1 | — | 95 | 1 | 1 | 98 | 2 | 100 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | (40) | $ | 823 | $ | 354 | $ | 105 | $ | (26) | $ | 1,216 | $ | (564) | $ | 652 |
(a)Includes nuclear fuel amortization of $35 million and $94 million, respectively, in the Texas and East segments.
(b)Other includes impairment of long-lived assets and other income, net.
| Three Months Ended September 30, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Asset Closure | Total Reportable Segments | Corporate and Other | Total | ||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues | $ | 4,251 | $ | 4,244 | $ | 1,853 | $ | 232 | $ | 11 | $ | 10,591 | $ | (4,303) | $ | 6,288 | |||||||||||||||||||||||||||||||
| Fuel, purchased power costs, and delivery fees (a) | (5,117) | (487) | (859) | (45) | (2) | (6,510) | 4,303 | (2,207) | |||||||||||||||||||||||||||||||||||||||
| Operating costs | (47) | (242) | (296) | (11) | (19) | (615) | (1) | (616) | |||||||||||||||||||||||||||||||||||||||
| Selling, general, and administrative expenses | (266) | (40) | (32) | (8) | (9) | (355) | (56) | (411) | |||||||||||||||||||||||||||||||||||||||
| Other segment items: | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | (31) | (155) | (241) | (15) | (7) | (449) | (17) | (466) | |||||||||||||||||||||||||||||||||||||||
| Interest expenses and related charges | (16) | 11 | 4 | 1 | (1) | (1) | (331) | (332) | |||||||||||||||||||||||||||||||||||||||
| Income tax expense | — | — | — | — | — | — | (555) | (555) | |||||||||||||||||||||||||||||||||||||||
| Other (b) | — | 23 | 97 | 1 | 7 | 128 | 8 | 136 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | (1,226) | $ | 3,354 | $ | 526 | $ | 155 | $ | (20) | $ | 2,789 | $ | (952) | $ | 1,837 |
(a)Includes nuclear fuel amortization of $28 million and $95 million, respectively, in the Texas and East segments.
(b)Other includes other income, net.
| Nine Months Ended September 30, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Asset Closure | Total Reportable Segments | Corporate and Other | Total | ||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues | $ | 10,839 | $ | 3,797 | $ | 4,610 | $ | 347 | $ | 26 | $ | 19,619 | $ | (6,465) | $ | 13,154 | |||||||||||||||||||||||||||||||
| Fuel, purchased power costs, and delivery fees (a) | (8,848) | (1,509) | (2,784) | (119) | — | (13,260) | 6,469 | (6,791) | |||||||||||||||||||||||||||||||||||||||
| Operating costs | (131) | (778) | (1,020) | (45) | (113) | (2,087) | 6 | (2,081) | |||||||||||||||||||||||||||||||||||||||
| Selling, general, and administrative expenses | (769) | (122) | (175) | (11) | (52) | (1,129) | (125) | (1,254) | |||||||||||||||||||||||||||||||||||||||
| Other segment items: | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | (70) | (477) | (876) | (45) | 2 | (1,466) | (57) | (1,523) | |||||||||||||||||||||||||||||||||||||||
| Interest expenses and related charges | (53) | 41 | 36 | 4 | (3) | 25 | (933) | (908) | |||||||||||||||||||||||||||||||||||||||
| Income tax expense | — | — | (1) | — | — | (1) | (103) | (104) | |||||||||||||||||||||||||||||||||||||||
| Other (b) | 1 | 14 | 194 | 1 | 3 | 213 | 5 | 218 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 969 | $ | 966 | $ | (16) | $ | 132 | $ | (137) | $ | 1,914 | $ | (1,203) | $ | 711 | |||||||||||||||||||||||||||||||
| Capital expenditures, including nuclear fuel and excluding growth expenditures (c) | $ | 10 | $ | 714 | $ | 444 | $ | 117 | $ | — | $ | 1,285 | $ | 411 | $ | 1,696 |
(a)Includes nuclear fuel amortization of $96 million and $270 million, respectively, in the Texas and East segments.
(b)Other includes impairment of long-lived assets and other income, net.
(c)Corporate and other includes $380 million of nuclear fuel purchases.
| Nine Months Ended September 30, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Asset Closure | Total Reportable Segments | Corporate and Other | Total | ||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues | $ | 9,913 | $ | 4,924 | $ | 4,241 | $ | 701 | $ | 29 | $ | 19,808 | $ | (6,621) | $ | 13,187 | |||||||||||||||||||||||||||||||
| Fuel, purchased power costs, and delivery fees (a) | (8,724) | (1,249) | (2,000) | (164) | (5) | (12,142) | 6,622 | (5,520) | |||||||||||||||||||||||||||||||||||||||
| Operating costs | (118) | (753) | (774) | (39) | (56) | (1,740) | (2) | (1,742) | |||||||||||||||||||||||||||||||||||||||
| Selling, general, and administrative expenses | (715) | (116) | (93) | (14) | (34) | (972) | (165) | (1,137) | |||||||||||||||||||||||||||||||||||||||
| Other segment items: | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | (85) | (423) | (684) | (43) | (21) | (1,256) | (50) | (1,306) | |||||||||||||||||||||||||||||||||||||||
| Interest expenses and related charges | (38) | 33 | 4 | 1 | (3) | (3) | (740) | (743) | |||||||||||||||||||||||||||||||||||||||
| Income tax expense | — | — | — | — | — | — | (694) | (694) | |||||||||||||||||||||||||||||||||||||||
| Other (b) | (1) | 29 | 177 | — | 14 | 219 | 58 | 277 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 232 | $ | 2,445 | $ | 871 | $ | 442 | $ | (76) | $ | 3,914 | $ | (1,592) | $ | 2,322 | |||||||||||||||||||||||||||||||
| Capital expenditures, including nuclear fuel and excluding growth expenditures (c) | $ | 3 | $ | 544 | $ | 393 | $ | 44 | $ | 1 | $ | 985 | $ | 486 | $ | 1,471 |
(a)Includes nuclear fuel amortization of $80 million and $189 million, respectively, in the Texas and East segments.
(b)Other includes other income, net and the impacts of the Tax Receivable Agreement.
(c)Corporate and other includes $445 million of nuclear fuel purchases.
17. SUPPLEMENTARY FINANCIAL INFORMATION
Other Income, Net
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| NDT net income (a) | $ | 100 | $ | 95 | $ | 197 | $ | 170 | |||||||||||||||
| Insurance settlements (b) | — | 21 | 80 | 22 | |||||||||||||||||||
| Gain on sale of land | — | 5 | — | 6 | |||||||||||||||||||
| Gain on TRA settlement (c) | — | — | — | 10 | |||||||||||||||||||
| Interest income | 4 | 9 | 14 | 50 | |||||||||||||||||||
| All other | 1 | 6 | — | 24 | |||||||||||||||||||
| Total other income, net | $ | 105 | $ | 136 | $ | 291 | $ | 282 |
(a)Includes interest, dividends, and net realized and unrealized gains (losses) associated with NDTs of the PJM nuclear facilities. Reported in the East segment.
(b)The $80 million of insurance settlements recognized in 2025 represents the involuntary conversion gain for Martin Lake Incident insurance proceeds reported in the Texas segment. See Note 1 for additional information.
(c)Reported in Corporate and Other.
Inventories by Major Category
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Materials and supplies | $ | 560 | $ | 533 | |||||||
| Fuel stock | 370 | 403 | |||||||||
| Natural gas in storage | 40 | 34 | |||||||||
| Total inventories | $ | 970 | $ | 970 |
Investments
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Nuclear decommissioning trusts | $ | 4,930 | $ | 4,440 | |||||||
| Assets related to employee benefit plans | 13 | 14 | |||||||||
| Land investments | 42 | 42 | |||||||||
| Other investments | 23 | 16 | |||||||||
| Total investments | $ | 5,008 | $ | 4,512 |
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Retirement and other employee benefits | $ | 200 | $ | 224 | |||||||
| Identifiable intangible liabilities | 141 | 155 | |||||||||
| Regulatory liability (a) | 691 | 452 | |||||||||
| Operating lease liabilities | 72 | 98 | |||||||||
| Finance lease liabilities | 217 | 218 | |||||||||
| Liability for third-party remediation | 8 | 8 | |||||||||
| Accrued severance costs | 34 | 36 | |||||||||
| Tax Receivable Agreement obligation | 9 | 14 | |||||||||
| Other accrued expenses | 82 | 65 | |||||||||
| Total other noncurrent liabilities and deferred credits | $ | 1,454 | $ | 1,270 |
(a)As of September 30, 2025 and 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 $691 million and $452 million, respectively.
Supplemental Cash Flow Information
The following table reconciles cash, cash equivalents and restricted cash reported in the condensed consolidated statements of cash flows to the amounts reported in the condensed consolidated balance sheets at September 30, 2025 and December 31, 2024:
| September 30, 2025 | December 31, 2024 | ||||||||||
| (in millions) | |||||||||||
| Cash and cash equivalents | $ | 602 | $ | 1,188 | |||||||
| Restricted cash included in current assets | 30 | 28 | |||||||||
| Restricted cash included in noncurrent assets | 6 | 6 | |||||||||
| Total cash, cash equivalents and restricted cash | $ | 638 | $ | 1,222 |
The following table summarizes our supplemental cash flow information for the nine months ended September 30, 2025 and 2024. Non-cash investing and financing activities for the nine months ended September 30, 2024 includes activity related to the Energy Harbor Merger (see Note 2 for additional information).
| Nine Months Ended September 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| (in millions) | |||||||||||
| Cash payments related to: | |||||||||||
| Interest paid | $ | 799 | $ | 709 | |||||||
| Capitalized interest | (86) | (52) | |||||||||
| Interest paid (net of capitalized interest) | $ | 713 | $ | 657 | |||||||
For the nine months ended September 30, 2025 and 2024, we paid federal income tax of $11 million and $2 million, respectively, paid state income taxes of $70 million and $52 million respectively, and received state tax refunds of zero and $8 million, respectively.
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