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, | ||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| Operating revenues (Note 4) | $ | 6,288 | $ | 4,086 | $ | 13,187 | $ | 11,701 | |||||||||||||||
| Fuel, purchased power costs and delivery fees | (2,207) | (2,109) | (5,520) | (5,754) | |||||||||||||||||||
| Operating costs | (616) | (411) | (1,742) | (1,277) | |||||||||||||||||||
| Depreciation and amortization | (466) | (375) | (1,306) | (1,109) | |||||||||||||||||||
| Selling, general and administrative expenses | (411) | (357) | (1,137) | (953) | |||||||||||||||||||
| Impairment of long-lived assets (Note 17) | — | — | — | (49) | |||||||||||||||||||
| Operating income | 2,588 | 834 | 3,482 | 2,559 | |||||||||||||||||||
| Other income (Note 17) | 139 | 32 | 292 | 174 | |||||||||||||||||||
| Other deductions (Note 17) | (3) | (3) | (10) | (9) | |||||||||||||||||||
| Interest expense and related charges (Note 17) | (332) | (143) | (743) | (450) | |||||||||||||||||||
| Impacts of Tax Receivable Agreement (Note 12) | — | (49) | (5) | (128) | |||||||||||||||||||
| Net income before income taxes | 2,392 | 671 | 3,016 | 2,146 | |||||||||||||||||||
| Income tax expense (Note 5) | (555) | (169) | (694) | (470) | |||||||||||||||||||
| Net income | $ | 1,837 | $ | 502 | $ | 2,322 | $ | 1,676 | |||||||||||||||
| Net (income) loss attributable to noncontrolling interest | 51 | — | (104) | 1 | |||||||||||||||||||
| Net income attributable to Vistra | $ | 1,888 | $ | 502 | $ | 2,218 | $ | 1,677 | |||||||||||||||
| Cumulative dividends attributable to preferred stock | (48) | (37) | (144) | (112) | |||||||||||||||||||
| Net income attributable to Vistra common stock | $ | 1,840 | $ | 465 | $ | 2,074 | $ | 1,565 | |||||||||||||||
| Weighted average shares of common stock outstanding: | |||||||||||||||||||||||
| Basic | 342,969,916 | 366,570,040 | 346,315,125 | 374,323,466 | |||||||||||||||||||
| Diluted | 350,203,692 | 372,149,099 | 353,805,937 | 379,102,358 | |||||||||||||||||||
| Net income per weighted average share of common stock outstanding: | |||||||||||||||||||||||
| Basic | $ | 5.36 | $ | 1.27 | $ | 5.99 | $ | 4.18 | |||||||||||||||
| Diluted | $ | 5.25 | $ | 1.25 | $ | 5.86 | $ | 4.13 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited) (Millions of Dollars)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| Net income | $ | 1,837 | $ | 502 | $ | 2,322 | $ | 1,676 | |||||||||||||||
| Other comprehensive income, net of tax effects: | |||||||||||||||||||||||
| Effects related to pension and other retirement benefit obligations (net of tax expense (benefit) of $—, $—, $— and $1) | 1 | (2) | 1 | 3 | |||||||||||||||||||
| Total other comprehensive income | 1 | (2) | 1 | 3 | |||||||||||||||||||
| Comprehensive income | $ | 1,838 | $ | 500 | $ | 2,323 | $ | 1,679 | |||||||||||||||
| Comprehensive (income) loss attributable to noncontrolling interest | 51 | — | (104) | 1 | |||||||||||||||||||
| Comprehensive income attributable to Vistra | $ | 1,889 | $ | 500 | $ | 2,219 | $ | 1,680 |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars) | |||||||||||
| Nine Months Ended September 30, | |||||||||||
| 2024 | 2023 | ||||||||||
| Cash flows — operating activities: | |||||||||||
| Net income | $ | 2,322 | $ | 1,676 | |||||||
| Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||
| Depreciation and amortization | 1,891 | 1,442 | |||||||||
| Deferred income tax expense, net | 666 | 437 | |||||||||
| Gain on sale of land | — | (95) | |||||||||
| Impairment of long-lived assets | — | 49 | |||||||||
| Unrealized net gain from mark-to-market valuations of commodities | (1,725) | (855) | |||||||||
| Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps | 26 | (65) | |||||||||
| Unrealized net gain from nuclear decommissioning trusts | (133) | — | |||||||||
| Asset retirement obligation accretion expense | 84 | 26 | |||||||||
| Impacts of Tax Receivable Agreement | 5 | 128 | |||||||||
| Gain on TRA repurchase and tender offers | (10) | — | |||||||||
| Bad debt expense | 132 | 131 | |||||||||
| Stock-based compensation | 76 | 63 | |||||||||
| Other, net | (9) | 39 | |||||||||
| Changes in operating assets and liabilities: | |||||||||||
| Margin deposits, net | 855 | 2,271 | |||||||||
| Accrued interest | 11 | (47) | |||||||||
| Accrued taxes | (40) | (38) | |||||||||
| Accrued employee incentive | (78) | (23) | |||||||||
| Other operating assets and liabilities | (863) | (567) | |||||||||
| Cash provided by operating activities | 3,210 | 4,572 | |||||||||
| Cash flows — investing activities: | |||||||||||
| Capital expenditures, including nuclear fuel purchases and LTSA prepayments | (1,648) | (1,262) | |||||||||
| Energy Harbor acquisition (net of cash acquired) | (3,065) | — | |||||||||
| Proceeds from sales of nuclear decommissioning trust fund securities | 1,573 | 478 | |||||||||
| Investments in nuclear decommissioning trust fund securities | (1,590) | (495) | |||||||||
| Proceeds from sales of environmental allowances | 147 | 59 | |||||||||
| Purchases of environmental allowances | (511) | (277) | |||||||||
| Proceeds from sale of property, plant and equipment, including nuclear fuel | 137 | 111 | |||||||||
| Other, net | (2) | 4 | |||||||||
| Cash used in investing activities | (4,959) | (1,382) | |||||||||
| Cash flows — financing activities: | |||||||||||
| Issuances of long-term debt | 2,200 | 1,750 | |||||||||
| Repayments/repurchases of debt | (2,269) | (21) | |||||||||
| Net borrowings (repayments) under accounts receivable financing | 750 | (425) | |||||||||
| Borrowings under Revolving Credit Facility | 50 | 100 | |||||||||
| Repayments under Revolving Credit Facility | (50) | (350) | |||||||||
| Borrowings under Commodity-Linked Facility | 1,802 | — | |||||||||
| Repayments under Commodity-Linked Facility | (1,802) | (400) | |||||||||
| Debt issuance costs | (32) | (29) | |||||||||
| Stock repurchases | (1,021) | (866) | |||||||||
| Dividends paid to common stockholders | (230) | (228) | |||||||||
| Dividends paid to preferred stockholders | (98) | (75) |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars) | |||||||||||
| Nine Months Ended September 30, | |||||||||||
| 2024 | 2023 | ||||||||||
| Dividends paid to noncontrolling interest in subsidiary | (15) | — | |||||||||
| TRA Repurchase and tender offer — return of capital | (122) | — | |||||||||
| Other, net | (13) | 54 | |||||||||
| Cash used in financing activities | (850) | (490) | |||||||||
| Net change in cash, cash equivalents and restricted cash | (2,599) | 2,700 | |||||||||
| Cash, cash equivalents and restricted cash — beginning balance | 3,539 | 525 | |||||||||
| Cash, cash equivalents and restricted cash — ending balance | $ | 940 | $ | 3,225 |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data) | |||||||||||
| September 30, 2024 | December 31, 2023 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 905 | $ | 3,485 | |||||||
| Restricted cash (Note 17) | 29 | 40 | |||||||||
| Trade accounts receivable — net (Note 4) | 2,179 | 1,674 | |||||||||
| Income taxes receivable | 20 | 6 | |||||||||
| Inventories (Note 17) | 949 | 740 | |||||||||
| Commodity and other derivative contractual assets (Note 10) | 2,854 | 3,645 | |||||||||
| Margin deposits related to commodity contracts | 519 | 1,244 | |||||||||
| Margin deposits posted under affiliate financing agreement (Note 8) | 451 | 439 | |||||||||
| Prepaid expense and other current assets | 625 | 364 | |||||||||
| Total current assets | 8,531 | 11,637 | |||||||||
| Restricted cash (Note 17) | 6 | 14 | |||||||||
| Investments (Note 17) | 4,520 | 2,035 | |||||||||
| Property, plant and equipment — net (Note 17) | 18,388 | 12,432 | |||||||||
| Operating lease right-of-use assets | 109 | 50 | |||||||||
| Goodwill (Note 7) | 2,802 | 2,583 | |||||||||
| Identifiable intangible assets — net (Note 7) | 2,157 | 1,864 | |||||||||
| Commodity and other derivative contractual assets (Note 10) | 886 | 577 | |||||||||
| Accumulated deferred income taxes | — | 1,223 | |||||||||
| Other noncurrent assets | 479 | 551 | |||||||||
| Total assets | $ | 37,878 | $ | 32,966 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts receivable financing (Note 9) | $ | 750 | $ | — | |||||||
| Long-term debt due currently (Note 9) | 785 | 2,286 | |||||||||
| Trade accounts payable | 1,291 | 1,147 | |||||||||
| Commodity and other derivative contractual liabilities (Note 10) | 3,563 | 5,258 | |||||||||
| Margin deposits related to commodity contracts | 175 | 45 | |||||||||
| Accrued taxes other than income | 199 | 203 | |||||||||
| Accrued interest | 222 | 206 | |||||||||
| Asset retirement obligations (Note 13) | 102 | 124 | |||||||||
| Operating lease liabilities | 13 | 7 | |||||||||
| Other current liabilities | 560 | 547 | |||||||||
| Total current liabilities | 7,660 | 9,823 | |||||||||
| Margin deposits financing with affiliate (Note 8) | 451 | 439 | |||||||||
| Long-term debt, less amounts due currently (Note 9) | 13,945 | 12,116 | |||||||||
| Operating lease liabilities | 99 | 48 | |||||||||
| Commodity and other derivative contractual liabilities (Note 10) | 1,141 | 1,688 | |||||||||
| Accumulated deferred income taxes | 839 | 1 | |||||||||
| Tax Receivable Agreement obligation (Note 12) | 15 | 164 | |||||||||
| Asset retirement obligations (Note 13) | 3,884 | 2,414 | |||||||||
| Other noncurrent liabilities and deferred credits (Note 17) | 1,191 | 951 | |||||||||
| Total liabilities | 29,225 | 27,644 |
See Notes to Condensed Consolidated Financial Statements
| VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data) | |||||||||||
| September 30, 2024 | December 31, 2023 | ||||||||||
| Commitments and Contingencies (Note 14) | |||||||||||
| Redeemable noncontrolling interest (Note 2) | 3,198 | — | |||||||||
| Total equity (Note 15): | |||||||||||
| Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation preference — $1,000; shares outstanding: September 30, 2024 and December 31, 2023— 1,000,000); Series B (liquidation preference — $1,000; shares outstanding: September 30, 2024 and December 31, 2023 — 1,000,000); Series C (liquidation preference — $1,000; shares outstanding: September 30, 2024 — 476,066 and December 31, 2023 — 476,081) | 2,476 | 2,476 | |||||||||
| Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: September 30, 2024 — 340,717,442; December 31, 2023 — 351,457,016) | 5 | 5 | |||||||||
| Treasury stock, at cost (shares: September 30, 2024 — 207,378,586; December 31, 2023 — 192,178,156) | (5,684) | (4,662) | |||||||||
| Additional paid-in-capital | 9,396 | 10,095 | |||||||||
| Retained deficit | (759) | (2,613) | |||||||||
| Accumulated other comprehensive income | 7 | 6 | |||||||||
| Stockholders' equity | 5,441 | 5,307 | |||||||||
| Noncontrolling interest in subsidiary | 14 | 15 | |||||||||
| Total equity | 5,455 | 5,322 | |||||||||
| Total liabilities, redeemable noncontrolling interest and equity | $ | 37,878 | $ | 32,966 |
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 | Retained 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 | — | — | — | 35 | — | — | 35 | — | 35 | ||||||||||||||||||||||||||||||||||||||||||||
| Equity issued in subsidiary to acquire Energy Harbor (a) | — | — | — | 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 (loss) | — | — | — | — | 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 (a) | — | — | — | (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 |
(a)See Note 2 for additional information regarding activity associated with noncontrolling interest.
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 | Retained Deficit | Accumulated Other Comprehensive Income (Loss) | Total Stockholders' Equity | Noncontrolling Interest in Subsidiary | Total Equity | |||||||||||||||||||||||||||||||||||||||||||||
| Balances at December 31, 2022 | $ | 2,000 | $ | 5 | $ | (3,395) | $ | 9,928 | $ | (3,643) | $ | 7 | $ | 4,902 | $ | 16 | $ | 4,918 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (311) | — | — | — | (311) | — | (311) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 24 | — | — | 24 | — | 24 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | 699 | — | 699 | (1) | 698 | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (77) | — | (77) | — | (77) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (37) | — | (37) | — | (37) | ||||||||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income | — | — | — | — | — | 1 | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at March 31, 2023 | $ | 2,000 | $ | 5 | $ | (3,706) | $ | 9,952 | $ | (3,058) | $ | 8 | $ | 5,201 | $ | 15 | $ | 5,216 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (249) | — | — | — | (249) | — | (249) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 42 | — | — | 42 | — | 42 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 476 | — | 476 | — | 476 | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (76) | — | (76) | — | (76) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (38) | — | (38) | — | (38) | ||||||||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income | — | — | — | — | — | 4 | 4 | — | 4 | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (1) | — | — | (1) | — | (1) | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at June 30, 2023 | $ | 2,000 | $ | 5 | $ | (3,955) | $ | 9,993 | $ | (2,696) | $ | 12 | $ | 5,359 | $ | 15 | $ | 5,374 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (323) | — | — | — | (323) | — | (323) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 81 | — | — | 81 | — | 81 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 502 | — | 502 | — | 502 | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (75) | — | (75) | — | (75) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (37) | — | (37) | — | (37) | ||||||||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income | — | — | — | — | — | (2) | (2) | — | (2) | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | 1 | — | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Balances at September 30, 2023 | $ | 2,000 | $ | 5 | $ | (4,278) | $ | 10,075 | $ | (2,306) | $ | 10 | $ | 5,506 | $ | 15 | $ | 5,521 |
See Notes to Condensed Consolidated Financial Statements
VISTRA CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
**1.**BUSINESS, BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Description of Business
References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary of Terms and Abbreviations for defined terms.
Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.
Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 16 for further information concerning our reportable business segments.
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 2023 Form 10-K. 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. All such adjustments are of a normal nature. All intercompany items and transactions have been eliminated in consolidation.
A noncontrolling interest in a consolidated subsidiary represents the portion of the equity in a subsidiary not attributable, directly or indirectly, to the Company. Noncontrolling interests are presented as a separate component of equity in the condensed consolidated balance sheets and the presentation of net income is modified to present earnings attributed to controlling and noncontrolling interests. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests.
Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the audited financial statements and related notes contained in our 2023 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated. Certain prior period amounts have been reclassified to conform with the current year presentation.
Significant Accounting Policies
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value as of the acquisition date. The excess of the purchase price over those fair values is recognized as goodwill (if any). During the measurement period, which may be up to one year from the acquisition date, we may record adjustments to the assets acquired and liabilities assumed in the period in which they are determined.
Nuclear Decommissioning Trusts (NDTs)
The NRC is responsible for regulating all nuclear power plants in the U.S. This regulatory oversight results in specific accounting considerations for nuclear plant decommissioning. Our NDTs hold funds primarily for the ultimate decommissioning of our nuclear power plants. Each unit has its own NDT and funds from one unit may not be used to fund decommissioning obligations of another unit.
Decommissioning costs associated with the Comanche Peak nuclear generation facility in Texas are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the NDT. Income and expense, including gains and losses associated with the NDT assets and the related decommissioning liability are offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates.
The NDTs associated with our PJM nuclear facilities have been funded with amounts collected from the previous owners and their respective utility customers. Any shortfall of funds necessary for decommissioning the PJM nuclear facilities, determined for each generating station unit, are required to be funded by us. Investments in the PJM NDTs are carried at fair value and gains and losses are recognized as other income or other deductions in the condensed consolidated statements of operations. NDTs are invested in diversified portfolios of securities generally designed to achieve a return sufficient to fund the future decommissioning work. We retain any funds remaining in the trusts of the PJM nuclear facilities after all decommissioning has been completed.
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.
Adoption of Accounting Standards
Improvements to Reportable Segment Disclosures
In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures, to improve the disclosures about reportable segments and add more detailed information about a reportable segment's expenses. The amendments in the ASU require public entities to disclose, on an annual and interim basis, significant segment expenses that are regularly provided to the chief operating decision maker (CODM) and included within each reported measure of segment profit or loss, other segment items by reportable segment, the title and position of the CODM, and an explanation of how the CODM uses the reported measures of segment profit or loss in assessing segment performance and deciding how to allocate resources. The ASU does not change the definition of a segment, the method for determining segments, the criteria for aggregating operating segments into reportable segments, or the current specifically enumerated segment expenses that are required to be disclosed. The Company will adopt the amendments in this ASU for its fiscal year ended December 31, 2024 and interim periods within its fiscal year ended December 31, 2025. The amendment will be applied retrospectively to all prior periods presented. The ASU will result in additional disclosures, but the Company does not expect the adoption to have a material impact on our consolidated financial statements.
Improvements to Income Tax Disclosures
In December 2023, the FASB issued ASU No. 2023-09 (ASU 2023-09), Income Taxes (Topic 740): Improvements to Income Tax Disclosures to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. As the amendments apply to income tax disclosures only, the Company does not expect the 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 can be applied prospectively or retrospectively. Early adoption is permitted. We are currently evaluating the impact this ASU will have on our consolidated financial statements and related disclosures.
Recent Developments
Nuclear PTCs
The IRA introduced a PTC for nuclear energy under Internal Revenue Code Section 45U that is available to existing nuclear units from 2024 through 2032. All our nuclear units qualify for this credit, which is based on the amount of electricity sold during the taxable year and is subject to a phase-out based on annual gross receipts. While we believe we meet the conditions for earning the nuclear PTC, we are awaiting guidance from the U.S. Treasury and IRS on the implementation of IRC Section 45U, particularly on the definition of gross receipts including the treatment of hedges, among other key components to industry interpretations of the definition. The forthcoming guidance could have a significant impact on our estimate of PTC revenues. The amount of nuclear PTCs recorded could have a material impact on our 2024 financial statements.
Tax Credit Transfer Agreement
In October 2024, we sold $156 million of transferable ITCs we recognized as a result of the Moss Landing Phase III site reaching commercial operations in June 2023, as well as $8 million and $3 million of PTCs generated at our Emerald Grove and Brightside solar facilities in 2023, respectively. Vistra received cash consideration from the sale in October 2024.
Debt and Financing Activity
See Note 9 for information on amendments to the Revolving Credit Facility and the Commodity-Linked Facility in October 2024.
Share Repurchase Program
In October 2024, the Board authorized $1.0 billion for additional repurchases under the Share Repurchase Program (see Note 15).
2. ACQUISITIONS
Energy Harbor Business Combination
On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly-owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (Avenue) exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively, Energy Harbor Merger). The Energy Harbor Merger combines Energy Harbor's and Vistra's nuclear and retail businesses and certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free technologies (dispatchable and renewables/storage) and the retail business.
The Energy Harbor Merger was accounted for using the acquisition method in accordance with ASC 805, Business Combinations (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated fair values on the Merger Date. The combined results of operations are reported in the 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 in the second and third quarters of 2024. Additional adjustments may be made in subsequent periods (up to one year from the acquisition date) as information necessary to complete the fair value analysis is obtained. The provisional fair values assigned to assets acquired and liabilities assumed are as follows:
| Updated Fair Value as of September 30, 2024 | Measurement Period Adjustments recorded through September 30, 2024 | ||||||||||
| (in millions) | |||||||||||
| Cash and cash equivalents | $ | 35 | $ | 5 | |||||||
| Trade accounts receivables, inventories, prepaid expenses and other current assets | 548 | 10 | |||||||||
| Investments (a) | 2,021 | — | |||||||||
| Property, plant and equipment (b) | 5,746 | 126 | |||||||||
| Identifiable intangible assets (c) | 444 | 16 | |||||||||
| Commodity and other derivative contractual assets (d) | 123 | (17) | |||||||||
| Other noncurrent assets | 6 | (2) | |||||||||
| Total identifiable assets acquired | 8,923 | 138 | |||||||||
| Trade accounts payable and other current liabilities | 283 | 20 | |||||||||
| Long-term debt, including amounts due currently | 413 | — | |||||||||
| Commodity and other derivative contractual liabilities (d) | 173 | (6) | |||||||||
| Accumulated deferred income taxes | 1,395 | 31 | |||||||||
| Asset retirement obligations (e) | 1,368 | — | |||||||||
| Identifiable intangible liabilities | 87 | 14 | |||||||||
| Other noncurrent liabilities and deferred credits | 16 | 4 | |||||||||
| Total identifiable liabilities assumed | 3,735 | 63 | |||||||||
| Identifiable net assets acquired | 5,188 | 75 | |||||||||
| Goodwill (f) | 219 | (75) | |||||||||
| 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 by Vistra Vision from combining operations of Energy Harbor with the contributed net assets of 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 and 2023 assumes that the Energy Harbor Merger occurred on January 1, 2023. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Energy Harbor Merger been completed on January 1, 2023, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Revenues | $ | 6,288 | $ | 4,872 | $ | 13,911 | $ | 13,456 | |||||||||||||||
| Net income | $ | 1,837 | $ | 379 | $ | 2,411 | $ | 1,109 | |||||||||||||||
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 $8 million for the three months ended September 30, 2024 and 2023, respectively, and $25 million and $21 million for the nine months ended September 30, 2024 and 2023, respectively, and are classified as selling, general and administrative expenses in the condensed consolidated statements of operations.
Acquisition of Non-Controlling Interest
On September 18, 2024 (the UPA Transaction Date), 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 has agreed to purchase each of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision for $3.248 billion in cash, not including the adjustment for dividends of $165 million (collectively, the Transaction). If Nuveen and Avenue receive less than $165 million in dividend distributions from Vistra Vision for the remainder of 2024, then the purchase price payable on the Closing Date will be adjusted upward by the difference, and if they receive distributions in excess of $165 million, then the purchase price payable at the Closing Date will be adjusted downward by the difference. Total scheduled payments under the UPAs are $3.413 billion. The Transaction is expected to close on December 31, 2024 (the Closing Date), subject to the satisfaction of certain closing conditions, at which time Vistra Vision Holdings will own 100% of the equity interests in Vistra Vision.
In accordance with the UPAs, the payments to Nuveen and Avenue will be paid in multiple installments through December 31, 2026. Vistra Vision Holdings' obligation to pay the purchase price will be guaranteed by Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes. Cash payments including estimated dividends for the remainder of 2024 and thereafter are expected as follows:
| September 30, 2024 | |||||
| (in millions) | |||||
| Remainder of 2024 | $ | 1,345 | |||
| 2025 | 1,114 | ||||
| 2026 | 954 | ||||
| 2027 | — | ||||
| 2028 | — | ||||
| Thereafter | — | ||||
| Total scheduled payments under the UPAs | $ | 3,413 |
The UPAs are subject to certain closing conditions outside our control and therefore represent conditional redemption obligations that require us to reflect the Transaction as redeemable noncontrolling interest within the mezzanine section of the condensed consolidated balance sheet. We accounted for the Transaction on the UPA Transaction Date as follows:
| Fair value of redeemable noncontrolling interest (a) | $ | 3,198 | |||
| Carrying value of NCI (b) | $ | (1,659) | |||
| Additional paid-in-capital | $ | (1,539) |
(a)Fair value represents the total scheduled payments under the UPAs of $3.413 billion discounted at 6%.
(b)Represents the carrying value of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision at the UPA Transaction Date.
Upon satisfaction of all closing conditions, remaining payment obligations will be reflected as a financing obligation on the consolidated balance sheets.
3. RETIREMENT OF GENERATION FACILITIES
Operational results for plants with defined retirement dates are included in our Sunset segment beginning in the quarter when a retirement plan is announced and moved to the Asset Closure segment at the beginning of the calendar year the retirement is expected to occur.
| Facility | Location | ISO/RTO | Fuel Type | Net Generation Capacity (MW) | Announced Retirement Date (a) | Segment | ||||||||||||||||||||||||||||||||
| Baldwin | Baldwin, IL | MISO | Coal | 1,185 | By the end of 2025 | Sunset | ||||||||||||||||||||||||||||||||
| Coleto Creek | Goliad, TX | ERCOT | Coal | 650 | By the end of 2027 (b) | Sunset | ||||||||||||||||||||||||||||||||
| Kincaid | Kincaid, IL | PJM | Coal | 1,108 | By the end of 2027 | Sunset | ||||||||||||||||||||||||||||||||
| Miami Fort | North Bend, OH | PJM | Coal | 1,020 | By the end of 2027 | Sunset | ||||||||||||||||||||||||||||||||
| Newton | Newton, IL | MISO/PJM | Coal | 615 | By the end of 2027 | Sunset | ||||||||||||||||||||||||||||||||
| Edwards | Bartonville, IL | MISO | Coal | 585 | Retired January 1, 2023 | Asset Closure | ||||||||||||||||||||||||||||||||
| Joppa | Joppa, IL | MISO | Coal | 802 | Retired September 1, 2022 | Asset Closure | ||||||||||||||||||||||||||||||||
| Joppa | Joppa, IL | MISO | Natural Gas | 221 | Retired September 1, 2022 | Asset Closure | ||||||||||||||||||||||||||||||||
| Zimmer | Moscow, OH | PJM | Coal | 1,300 | Retired June 1, 2022 | Asset Closure | ||||||||||||||||||||||||||||||||
| Total | 7,486 |
(a)Generation facilities may retire earlier than announced dates if economic or other conditions dictate.
(b)Following the retirement of Coleto Creek as a coal-fueled plant, the Company intends to repower it as a gas-fueled plant.
4. REVENUE
Revenue Disaggregation
Disaggregated revenue from contracts with customers, and other revenue included in total revenues in the condensed consolidated statements of operations is as follows:
| Three Months Ended September 30, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East (a) | West | Sunset | 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 | — | 95 | 251 | 51 | 123 | — | — | 520 | |||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (b) | — | — | 18 | — | — | — | — | 18 | |||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 94 | 76 | 58 | 23 | — | 1 | 252 | |||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 3,551 | 189 | 345 | 109 | 146 | — | 1 | 4,341 | |||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||
| Intangible amortization | 1 | — | — | — | (1) | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Transferable PTC revenues (c) | — | 4 | — | — | — | — | — | 4 | |||||||||||||||||||||||||||||||||||||||
| Hedging and other revenues (d) | 681 | 827 | 188 | 132 | 103 | 1 | 11 | 1,943 | |||||||||||||||||||||||||||||||||||||||
| Intersegment sales (e) | 18 | 3,084 | 991 | 1 | 221 | — | (4,315) | — | |||||||||||||||||||||||||||||||||||||||
| Total other revenues | 700 | 3,915 | 1,179 | 133 | 323 | 1 | (4,304) | 1,947 | |||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 4,251 | $ | 4,104 | $ | 1,524 | $ | 242 | $ | 469 | $ | 1 | $ | (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)Represents transferable PTCs generated from qualifying solar assets during the period.
(d)Includes $1.960 billion of unrealized net gains from mark-to-market valuations of commodity positions.
| Three Months Ended | Retail | Texas | East | West | Sunset | Asset Closure | Corporate and Other | Eliminations (1) | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | 308 | $ | 2,711 | $ | 340 | $ | 99 | $ | 82 | $ | 2 | $ | — | $ | (1,582) | $ | 1,960 |
(1)Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
(e)Texas, East, Sunset and West segments include $1.456 billion, $57 million, $68 million and $1 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.
| Three Months Ended September 30, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Consolidated | ||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers: | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail energy charge in ERCOT | $ | 2,667 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 2,667 | |||||||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest | 464 | — | — | — | — | — | — | 464 | |||||||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 697 | 354 | 79 | 159 | — | — | 1,289 | |||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (a) | — | — | 12 | — | 8 | — | — | 20 | |||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 202 | 75 | 50 | 22 | — | — | 349 | |||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 3,131 | 899 | 441 | 129 | 189 | — | — | 4,789 | |||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||
| Intangible amortization | 1 | — | — | — | (1) | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Transferable PTC revenues | — | 3 | — | — | — | — | — | 3 | |||||||||||||||||||||||||||||||||||||||
| Hedging and other revenues (b) | 251 | (987) | (135) | 215 | (51) | — | 1 | (706) | |||||||||||||||||||||||||||||||||||||||
| Intersegment sales (c) | — | 1,602 | 345 | — | 87 | — | (2,034) | — | |||||||||||||||||||||||||||||||||||||||
| Total other revenues | 252 | 618 | 210 | 215 | 35 | — | (2,033) | (703) | |||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 3,383 | $ | 1,517 | $ | 651 | $ | 344 | $ | 224 | $ | — | $ | (2,033) | $ | 4,086 |
(a)Represents net capacity sold in each ISO/RTO. The East segment includes $32 million of capacity sold offset by $20 million of capacity purchased. The Sunset segment includes $8 million of capacity sold. 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 $7 million offset by $8 million of capacity sold within the East segment.
(b)Includes $345 million of unrealized net losses from mark-to-market valuations of commodity positions.
| Three Months Ended | Retail | Texas | East | West | Sunset | Asset Closure | Corporate and Other | Eliminations (1) | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | $ | (70) | $ | (380) | $ | (128) | $ | 176 | $ | (118) | $ | 8 | $ | — | $ | 167 | $ | (345) |
(1)Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
(c)Texas, East and Sunset segments include $78 million, $81 million and $8 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 (a) | Texas | East (a) | West | Sunset | 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 | — | 213 | 621 | 168 | 288 | — | — | 1,290 | |||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (b) | — | — | 50 | — | 4 | — | — | 54 | |||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 325 | 211 | 171 | 101 | — | 1 | 809 | |||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 8,946 | 538 | 882 | 339 | 393 | — | 1 | 11,099 | |||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||
| Intangible amortization | — | — | — | — | (3) | — | — | (3) | |||||||||||||||||||||||||||||||||||||||
| Transferable PTC revenues (c) | — | 9 | — | — | — | — | — | 9 | |||||||||||||||||||||||||||||||||||||||
| Hedging and other revenues (d) | 924 | 283 | 200 | 385 | 277 | 1 | 12 | 2,082 | |||||||||||||||||||||||||||||||||||||||
| Intersegment sales (e) | 43 | 3,886 | 2,272 | 5 | 428 | — | (6,634) | — | |||||||||||||||||||||||||||||||||||||||
| Total other revenues | 967 | 4,178 | 2,472 | 390 | 702 | 1 | (6,622) | 2,088 | |||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 9,913 | $ | 4,716 | $ | 3,354 | $ | 729 | $ | 1,095 | $ | 1 | $ | (6,621) | $ | 13,187 |
(a)Includes six months of revenues associated with operations acquired in the Energy Harbor Merger.
(b)Represents net capacity sold in each ISO/RTO. The East segment includes $90 million of capacity sold offset by $40 million of capacity purchased. The Sunset segment includes $4 million of capacity sold. 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)Represents transferable PTCs generated from qualifying solar assets during the period.
(d)Includes $1.571 billion of unrealized net gains from mark-to-market valuations of commodity positions.
| Nine Months Ended | Retail | Texas | East | West | Sunset | Asset Closure | Corporate and Other | Eliminations (1) | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | (3) | $ | 1,436 | $ | 259 | $ | 320 | $ | 35 | $ | 8 | $ | — | $ | (484) | $ | 1,571 |
(1)Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
(e)Texas and Sunset segments include $547 million and $48 million, respectively, of intersegment unrealized net gains and East segment includes $114 million of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.
| Nine Months Ended September 30, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Sunset | Asset Closure | Eliminations / Corporate and Other | Consolidated | ||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Retail energy charge in ERCOT | $ | 6,079 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 6,079 | |||||||||||||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest | 1,242 | — | — | — | — | — | — | 1,242 | |||||||||||||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 929 | 756 | 316 | 279 | — | — | 2,280 | |||||||||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (a) | — | — | 42 | — | 35 | — | — | 77 | |||||||||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 411 | 584 | 128 | 123 | — | — | 1,246 | |||||||||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 7,321 | 1,340 | 1,382 | 444 | 437 | — | — | 10,924 | |||||||||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Intangible amortization | — | — | (2) | — | (2) | — | — | (4) | |||||||||||||||||||||||||||||||||||||||||||||
| Transferable PTC revenues | — | 8 | — | — | — | — | — | 8 | |||||||||||||||||||||||||||||||||||||||||||||
| Hedging and other revenues (b) | 840 | (1,233) | 288 | 349 | 528 | — | 1 | 773 | |||||||||||||||||||||||||||||||||||||||||||||
| Intersegment sales (c) | — | 2,946 | 1,637 | 6 | 403 | — | (4,992) | — | |||||||||||||||||||||||||||||||||||||||||||||
| Total other revenues | 840 | 1,721 | 1,923 | 355 | 929 | — | (4,991) | 777 | |||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 8,161 | $ | 3,061 | $ | 3,305 | $ | 799 | $ | 1,366 | $ | — | $ | (4,991) | $ | 11,701 |
(a)Represents net capacity sold in each ISO/RTO. The East segment includes $115 million of capacity sold offset by $73 million of capacity purchased. The Sunset segment includes $71 million of capacity sold offset by $36 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 $68 million offset by $58 million of capacity sold within the East segment.
(b)Includes $1.020 billion of unrealized net gains from mark-to-market valuations of commodity positions.
| Nine Months Ended | Retail | Texas | East | West | Sunset | Asset Closure | Corporate and Other | Eliminations (1) | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | $ | 95 | $ | (686) | $ | 1,017 | $ | 293 | $ | 462 | $ | 32 | $ | — | $ | (193) | $ | 1,020 |
(1)Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
(c)Texas segment includes $388 million of intersegment net losses and East and Sunset segments include $440 million and $144 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.
Performance Obligations
As of September 30, 2024, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers for which the total consideration is fixed and determinable at contract execution. Capacity revenues will be recognized assuming the performance obligations are met and as capacity is made available to the related ISOs/RTOs or counterparties.
| Balance of 2024 | 2025 | 2026 | 2027 | 2028 | 2029 and Thereafter | Total | |||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||
| Remaining performance obligations | $ | 138 | $ | 1,112 | $ | 797 | $ | 273 | $ | 122 | $ | 610 | $ | 3,052 |
Trade Accounts Receivable
| September 30, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Wholesale and retail trade accounts receivable | $ | 2,267 | $ | 1,735 | |||||||
| Allowance for uncollectible accounts | (88) | (61) | |||||||||
| Trade accounts receivable — net | $ | 2,179 | $ | 1,674 | |||||||
| Trade accounts receivable from contracts with customers — net | $ | 1,792 | $ | 1,239 | |||||||
| Other trade accounts receivable — net | 387 | 435 | |||||||||
| Trade accounts receivable — net | $ | 2,179 | $ | 1,674 |
Gross trade accounts receivable as of September 30, 2024 and December 31, 2023 include unbilled retail revenues of $917 million and $614 million, respectively.
Allowance for Uncollectible Accounts Receivable
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2024 | 2023 | ||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Allowance for uncollectible accounts receivable at beginning of period | $ | 61 | $ | 65 | |||||||||||||||||||
| Increase for bad debt expense | 132 | 131 | |||||||||||||||||||||
| Decrease for account write-offs | (105) | (110) | |||||||||||||||||||||
| Allowance for uncollectible accounts receivable at end of period | $ | 88 | $ | 86 |
5. INCOME TAXES
Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra serves as the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.
Income Tax (Expense) Benefit
The components of our income tax (expense) benefit are as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net income before income taxes | $ | 2,392 | $ | 671 | $ | 3,016 | $ | 2,146 | |||||||||||||||
| Income tax expense | $ | (555) | $ | (169) | $ | (694) | $ | (470) | |||||||||||||||
| Effective tax rate | 23.2 | % | 25.2 | % | 23.0 | % | 21.9 | % |
We evaluate and update our annual effective income tax rate on an interim basis based on current and forecasted earnings and tax laws.
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.
For the three months ended September 30, 2023, the effective tax rate of 25.2% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes. For the nine months ended September 30, 2023, the effective tax rate of 21.9% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes, partially offset by the release of uncertain tax positions related to the 2018 and 2019 IRS audit closed in the second quarter of 2023.
Inflation Reduction Act of 2022 (IRA)
In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. We do not expect Vistra to be subject to the CAMT in the 2024 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes. See Note 1 for discussion of the nuclear PTC introduced by the IRA.
Transferable ITCs
In June 2023, our 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III) commenced commercial operations. As a result of Moss Landing Phase III reaching commercial operations, in June 2023 we recognized $154 million of transferable ITCs associated with the project in other noncurrent assets in the condensed consolidated balance sheet. In September 2024, we recognized an additional $2 million of transferable ITCs associated with the project and reclassified the $156 million of credits to other current assets. In October 2024, these credits were sold for cash consideration (see Note 1).
Final Section 163(j) Regulations
The final Section 163(j) regulations, which limits qualified deductions for business interest expense, were issued in July 2020 and provided a critical correction to the proposed regulations regarding the computation of adjusted taxable income. As of January 1, 2022, certain provisions in the final Section 163(j) regulations have sunset, including the add-back of depreciation and amortization to adjusted taxable income. As a result, under the law as currently enacted, Vistra's deductible business interest expense was significantly limited for the 2023 tax year and will continue to be so limited under current law going forward. Vistra remains active in legislative monitoring and advocacy efforts to support a legislative solution to reinstate and make permanent the add-back of depreciation and amortization to adjusted taxable income.
6. 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, | ||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| (in millions, except share data) | |||||||||||||||||||||||
| Net income attributable to Vistra | $ | 1,888 | $ | 502 | $ | 2,218 | $ | 1,677 | |||||||||||||||
| 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) | — | (32) | — | |||||||||||||||||||
| Net income attributable to common stock — basic and diluted | 1,840 | 465 | $ | 2,074 | $ | 1,565 | |||||||||||||||||
| Weighted average shares of common stock outstanding: | |||||||||||||||||||||||
| Basic | 342,969,916 | 366,570,040 | 346,315,125 | 374,323,466 | |||||||||||||||||||
| Dilutive securities: Stock-based incentive compensation plan | 7,233,776 | 5,579,059 | 7,490,812 | 4,778,892 | |||||||||||||||||||
| Diluted | 350,203,692 | 372,149,099 | 353,805,937 | 379,102,358 | |||||||||||||||||||
| Net income per weighted average share of common stock outstanding: | |||||||||||||||||||||||
| Basic | $ | 5.36 | $ | 1.27 | $ | 5.99 | $ | 4.18 | |||||||||||||||
| Diluted | $ | 5.25 | $ | 1.25 | $ | 5.86 | $ | 4.13 |
Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 531 and 17,847 for the three months ended September 30, 2024 and 2023, respectively, and 11,210 and 1,491,299 shares for the nine months ended September 30, 2024 and 2023, respectively.
7. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
Goodwill
As of September 30, 2024 and December 31, 2023, the carrying value of goodwill totaled $2.802 billion and $2.583 billion, respectively.
| Retail Segment | Texas Segment | ||||||||||||||||||||||
| Retail Reporting Unit (a) | Texas Generation Reporting Unit | Total Goodwill | |||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Balance at December 31, 2023 | $ | 2,461 | $ | 122 | $ | 2,583 | |||||||||||||||||
| Goodwill recorded in connection with the Energy Harbor Merger (b) | 219 | ||||||||||||||||||||||
| Balance at September 30, 2024 | $ | 2,461 | $ | 122 | $ | 2,802 |
(a)Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight line basis.
(b)Allocation of goodwill attributable to the Energy Harbor acquisition to reporting units is pending completion of purchase accounting measurement period.
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are comprised of the following:
| September 30, 2024 | December 31, 2023 | |||||||||||||||||||||||||||||||||||||
| Identifiable Intangible Asset | Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | ||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||
| Retail customer relationships | $ | 2,173 | $ | 1,948 | $ | 225 | $ | 2,088 | $ | 1,866 | $ | 222 | ||||||||||||||||||||||||||
| Software and other technology-related assets | 581 | 277 | 304 | 536 | 315 | 221 | ||||||||||||||||||||||||||||||||
| Retail and wholesale contracts | 503 | 312 | 191 | 233 | 217 | 16 | ||||||||||||||||||||||||||||||||
| Long-term service agreements | 18 | 5 | 13 | 18 | 5 | 13 | ||||||||||||||||||||||||||||||||
| Other identifiable intangible assets (a) | 95 | 12 | 83 | 62 | 11 | 51 | ||||||||||||||||||||||||||||||||
| Total identifiable intangible assets subject to amortization | $ | 3,370 | $ | 2,554 | 816 | $ | 2,937 | $ | 2,414 | 523 | ||||||||||||||||||||||||||||
| Retail trade names (not subject to amortization) | 1,341 | 1,341 | ||||||||||||||||||||||||||||||||||||
| Total identifiable intangible assets | $ | 2,157 | $ | 1,864 |
(a)Includes environmental allowances (emissions allowances and renewable energy certificates) and mining development costs.
Identifiable intangible liabilities are comprised of the following:
| Identifiable Intangible Liability | September 30, 2024 | December 31, 2023 | ||||||||||||
| (in millions) | ||||||||||||||
| Long-term service agreements | $ | 111 | $ | 122 | ||||||||||
| Power and fuel purchase contracts | 52 | 9 | ||||||||||||
| Total identifiable intangible liabilities | $ | 163 | $ | 131 |
Expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the condensed consolidated statements of operations) are comprised of the following:
| Identifiable Intangible Assets/Liabilities | Condensed Consolidated Statements of Operations | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Retail customer relationships | Depreciation and amortization | $ | 29 | $ | 25 | $ | 82 | $ | 74 | ||||||||||||||||||||
| Software and other technology-related assets | Depreciation and amortization | 15 | 15 | 43 | 44 | ||||||||||||||||||||||||
| Retail and wholesale contracts | Operating revenues/fuel, purchased power costs and delivery fees | (5) | — | (9) | 6 | ||||||||||||||||||||||||
| Other identifiable intangible assets | Fuel, purchased power costs and delivery fees | 131 | 99 | 327 | 261 | ||||||||||||||||||||||||
| Total identifiable intangible assets expense, net (a) | $ | 170 | $ | 139 | $ | 443 | $ | 385 |
(a)Amounts exclude LTSA. 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 on 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, 2024, the estimated aggregate amortization expense of identifiable intangible assets, excluding environmental allowances, for each of the next five fiscal years is as shown below.
| Year | Estimated Amortization Expense | |||||||
| (in millions) | ||||||||
| 2024 | $ | 313 | ||||||
| 2025 | $ | 222 | ||||||
| 2026 | $ | 158 | ||||||
| 2027 | $ | 63 | ||||||
| 2028 | $ | 42 |
8. COLLATERAL FINANCING AGREEMENT WITH AFFILIATE
On June 15, 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed by the Company (the Trust) that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $450 million. The Trust is not consolidated by Vistra. The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S. Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S. dollars, the Eligible Assets). At the direction of Vistra Operations, the Eligible Assets held by the Trust can be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program.
Under the Facility Agreement, Vistra Operations has the right (Issuance Right), from time to time, to require the Trust to purchase from Vistra Operations up to $450 million aggregate principal amount of Vistra Operations' 7.233% Senior Secured Notes due 2028 (7.233% Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury Strips corresponding to the portion of the issuance right exercised at such time.
The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233% Senior Secured Notes to the holders of the P-Caps if its sole assets consist of 7.233% Senior Secured Notes that Vistra Operations is no longer entitled to repurchase.
Vistra Operations pays a facility fee (Facility Fee) to the Trust payable on each May 17 and November 17, commencing on November 17, 2023, to and including May 17, 2028 (each, a Distribution Date), and on certain other dates as provided in the Facility Agreement. The Facility Fee is generally calculated at a rate of 3.3608% per annum, applied to the maximum amount of 7.233% Senior Secured Notes that Vistra Operations could issue and sell to the Trust under the Facility Agreement as of the close of business on the business day immediately preceding the applicable Distribution Date.
As of September 30, 2024 and December 31, 2023, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $451 million and $439 million, respectively, and are reported in the condensed consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate.
9. DEBT, CREDIT FACILITIES AND FINANCINGS
Amounts in the table below represent the categories of debt obligations incurred by the Company.
| September 30, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Long-term debt, including amounts due currently: | |||||||||||
| Non-recourse debt | $ | 697 | $ | — | |||||||
| Recourse debt | 14,173 | 14,517 | |||||||||
| Long -term debt before unamortized premiums, discounts and issuance costs | 14,870 | 14,517 | |||||||||
| Unamortized premiums, discounts and issuance costs | (140) | (115) | |||||||||
| Long-term debt including debt due currently | $ | 14,730 | $ | 14,402 | |||||||
| Accounts receivable financing | $ | 750 | $ | — | |||||||
Long-Term Debt
Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company.
| September 30, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 | $ | 2,481 | $ | 2,500 | |||||||
| Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 | 697 | — | |||||||||
| Vistra Operations Senior Secured Notes: | |||||||||||
| 4.875% Senior Secured Notes, due May 13, 2024 | — | 400 | |||||||||
| 3.550% Senior Secured Notes, due July 15, 2024 | — | 1,500 | |||||||||
| 5.125% Senior Secured Notes, due May 13, 2025 | 744 | 1,100 | |||||||||
| 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 | — | |||||||||
| Total Vistra Operations Senior Secured Notes | 3,894 | 5,650 | |||||||||
| Energy Harbor Revenue Bonds: | |||||||||||
| 3.375% Revenue Bond, due August 1, 2029 | 100 | — | |||||||||
| 4.750% Revenue Bonds, due June 1, 2033 and July 1, 2033 | 285 | — | |||||||||
| 3.750% Revenue Bond, due October 1, 2047 | 46 | — | |||||||||
| Total Energy Harbor Revenue Bonds | 431 | — | |||||||||
| Vistra Operations Senior Unsecured Notes: | |||||||||||
| 5.500% Senior Unsecured Notes, due September 1, 2026 | 1,000 | 1,000 | |||||||||
| 5.625% Senior Unsecured Notes, due February 15, 2027 | 1,300 | 1,300 | |||||||||
| 5.000% Senior Unsecured Notes, due July 31, 2027 | 1,300 | 1,300 | |||||||||
| 4.375% Senior Unsecured Notes, due May 15, 2029 | 1,250 | 1,250 | |||||||||
| 7.750% Senior Unsecured Notes, due October 15, 2031 | 1,450 | 1,450 | |||||||||
| 6.875% Senior Unsecured Notes, due April 15, 2032 | 1,000 | — | |||||||||
| Total Vistra Operations Senior Unsecured Notes | 7,300 | 6,300 | |||||||||
| Other: | |||||||||||
| Equipment Financing Agreements | 67 | 67 | |||||||||
| Total other long-term debt | 67 | 67 | |||||||||
| Unamortized debt premiums, discounts and issuance costs | (140) | (115) | |||||||||
| Total long-term debt including amounts due currently | 14,730 | 14,402 | |||||||||
| Less amounts due currently | (785) | (2,286) | |||||||||
| Total long-term debt less amounts due currently | $ | 13,945 | $ | 12,116 |
Long-Term Debt Maturities
Long-term debt maturities as of September 30, 2024 are as follows:
| September 30, 2024 | |||||
| (in millions) | |||||
| Remainder of 2024 | $ | 20 | |||
| 2025 | 786 | ||||
| 2026 | 1,038 | ||||
| 2027 | 3,434 | ||||
| 2028 | 34 | ||||
| Thereafter | 9,558 | ||||
| Unamortized premiums, discounts and debt issuance costs | (140) | ||||
| Total long-term debt, including amounts due currently | $ | 14,730 |
Credit Facilities
Our credit facilities and related available capacity as of September 30, 2024 are presented below.
| September 30, 2024 | ||||||||||||||||||||||||||||||||||||||
| Credit Facilities | Maturity Date | Facility Limit | Cash Borrowings (Short-Term) | Cash Borrowings (Long-Term) | Letters of Credit Outstanding | Available Capacity | ||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||
| Revolving Credit Facility | April 29, 2027 | $ | 3,175 | $ | — | $ | — | $ | 718 | $ | 2,457 | |||||||||||||||||||||||||||
| Term Loan B-3 Facility | December 20, 2030 | 2,481 | — | 2,481 | — | — | ||||||||||||||||||||||||||||||||
| Total Vistra Operations Credit Facilities | $ | 5,656 | $ | — | $ | 2,481 | $ | 718 | $ | 2,457 | ||||||||||||||||||||||||||||
| Vistra Operations Commodity-Linked Facility | October 2, 2024 | 1,575 | — | — | — | 633 | ||||||||||||||||||||||||||||||||
| Vistra Zero Term Loan B Facility | April 30, 2031 | 697 | — | 697 | — | — | ||||||||||||||||||||||||||||||||
| Total credit facilities | $ | 7,928 | $ | — | $ | 3,178 | $ | 718 | $ | 3,090 | ||||||||||||||||||||||||||||
Vistra Operations Credit Facilities
As of September 30, 2024, the Vistra Operations Credit Facilities consisted of up to $5.656 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $3.175 billion (Revolving Credit Facility), including aggregate revolving letter of credit commitments of up to $2.940 billion, and term loans of $2.481 billion (Term Loan B-3 Facility). The Revolving Credit Facility is used for general corporate purposes. In October 2024, Vistra Operations amended the Revolving Credit Facility which, among other things, increased revolving credit commitments to $3.440 billion and extended the maturity date to October 11, 2029.
Under the Vistra Operations Credit Agreement, (i) the interest applicable to the Revolving Credit Facility is based on the forward-looking term rate based on SOFR (Term SOFR Rate) plus a spread that will range from 1.25% to 2.00% and (ii) the fee on any undrawn amounts with respect to the Revolving Credit Facility will range from 17.5 basis points to 35.0 basis points. Letters of credit issued under the Revolving Credit Facility bear interest that ranges from 1.25% to 2.00%. 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, 2024, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 1.725% and 27.0 basis points, respectively, and the applicable interest rate margin for the letters of credit issued under the Revolving Credit facility was 1.725%. The Vistra Operations Credit Facilities also provide for certain additional customary fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit.
The Term Loan B-3 Facility bears interest based on the applicable Term SOFR Rate, plus a fixed spread of 2.00%, and the weighted average interest rates before taking into consideration interest rate swaps (see Note 10) on outstanding borrowings of $2.481 billion was 6.85% as of September 30, 2024. 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.
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, 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), and there being no outstanding revolving credit commitments the maturities of which have not been extended to October 11, 2029 (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 agents 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. 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, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, for periods prior to the October 2024 amendment, was applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceeded 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio, which is based on the ratio of consolidated total debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 5.50 to 1.00). 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.
Vistra Operations Commodity-Linked Revolving Credit Facility
As of September 30, 2024, the Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) totaled $1.575 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. The Commodity-Linked Facility is used to support our hedging strategy. As of September 30, 2024, the borrowing base of $633 million is lower than the facility limit which represents the aggregate commitments of $1.575 billion. In October 2024, Vistra Operations amended the Commodity-Linked Facility which, among other things, increased the aggregate available commitments to $1.75 billion and extended the maturity date to October 1, 2025.
Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero. Vistra Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce outstanding borrowings to be less than or equal to the borrowing base. Vistra Operations intends to use any borrowings provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capital and general corporate purposes.
Under the Vistra Operations Commodity-Linked Credit Agreement, (i) the interest applicable to the Commodity-Linked Facility is based on the Term SOFR Rate plus a spread that will range from 1.25% to 2.00% and (ii) the fee on any undrawn amounts with respect to the Commodity-Linked Facility will range from 17.5 basis points to 35.0 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, 2024, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Commodity-Linked Facility and the fee on any undrawn amounts with respect to the Commodity-Linked Facility were 1.725% and 27.0 basis points, respectively.
The Vistra Operations Commodity-Linked Credit Agreement includes a covenant, solely during a compliance period (which, for periods prior to the October 2024 amendment, in general, was applicable when the aggregate revolving borrowings exceeded 30% of the revolving commitments), that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Commodity-Linked Facility, not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio, which is based on the ratio of consolidated total debt compared to an EBITDA calculation defined under the terms of the Commodity-Linked Facility, not to exceed 5.50 to 1.00).
Vistra Zero Non-recourse Credit Agreement
On March 26, 2024, Vistra Zero 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 borrowed in its entirety on March 26, 2024. Net proceeds of $690 million were used (i) to pay issuance costs and (ii) for working capital and general corporate purposes. Vistra Zero's obligations under the Vistra Zero Credit Agreement are guaranteed by certain subsidiaries of Vistra Zero, but are otherwise non-recourse to Vistra Operations and its other subsidiaries. Fees and expenses related to entering the agreement totaling $8 million and a discount totaling $4 million were capitalized as reductions in the carrying amount of the debt.
Under the Vistra Zero Credit Agreement, the interest applicable to the Term Loan B Facility is Term SOFR plus 2.75% per annum. The Term Loan B Facility is not subject to a floor or credit spread adjustment but is subject to a 1.0% "soft call" prepayment premium prior to the date that is six months following March 26, 2024. The weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings of $697 million was 7.60% as of September 30, 2024. Cash borrowings under the Term Loan B Facility are subject to required scheduled quarterly payments of $1.75 million. Amounts paid cannot be reborrowed.
The Vistra Zero Credit Agreement contains customary covenants and warranties which are generally consistent in scope with the Vistra Operations Credit Agreement, except that there is no financial maintenance covenant in the Vistra Zero Credit Agreement.
Letter of Credit Facilities
Vistra Operations Secured Letter of Credit Facilities
Between August 2020 and July 2024, we entered into uncommitted standby letter of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities). The Secured LOC Facilities may be renewed annually and are used for general corporate purposes. As of September 30, 2024, $1.162 billion of letters of credit were outstanding under the Secured LOC Facilities.
Each of the Secured LOC Facilities includes a covenant that requires the consolidated first lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00).
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, 2024, the total capacity was $500 million and $500 million of letters of credit were outstanding under the Alternative LOC Facilities. The commitments under the Alternative LOC Facilities terminate in December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities.
Energy Harbor Letter of Credit Facility
Energy Harbor and its subsidiaries were parties to a letter of credit facility that was secured by a first lien on the Energy Harbor assets (Energy Harbor LOC Facility). The Energy Harbor LOC Facility was terminated in April 2024.
Vistra Operations Senior Secured Notes
In May 2024 and July 2024, the 4.875% senior secured notes due May 2024 and the 3.550% senior secured notes due July 2024, respectively, were repaid at maturity.
In April 2024, Vistra Operations issued $500 million aggregate principal amount of 6.000% senior secured notes due 2034 (6.000% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The 6.000% Senior Secured Notes provide for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities, by and among the Issuer, as borrower, Vistra Intermediate Company LLC, the guarantors party thereto, and Citibank, N.A. as administrative and collateral agent. The 6.000% Senior Secured Notes mature in April 15, 2034, with interest payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024. Net proceeds totaling approximately $495 million, together with proceeds from the April 2024 issuance of 6.875% Senior Unsecured Notes discussed below and cash on hand, were to be used for general corporate purposes, including to refinance outstanding indebtedness (including the senior secured debt maturities in May 2024 and July 2024). Fees and expenses related to the offering, including commissions and the original issue discount, totaled $6 million and were capitalized as a reduction in the carrying amount of the debt.
Since 2019, Vistra Operations has issued and sold its senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the 3.550% senior secured notes due 2024, the 5.125% senior secured notes due 2025, the 3.700% senior secured notes due 2027, the 4.300% senior secured notes due 2029, the 6.950% senior secured notes due 2033 and the 6.000% Senior Secured Notes (collectively, as each may be amended or supplemented from time to time, 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, which consists of a substantial portion of the property, assets and rights owned by Vistra Operations and certain direct and indirect subsidiaries of Vistra Operations as subsidiary guarantors (collectively, the Guarantor Subsidiaries) as well as the stock of Vistra Operations held by Vistra Intermediate. The collateral securing the Senior Secured Notes will be released if Vistra Operations' senior, unsecured long-term debt securities obtain an investment grade rating from two out of the three rating agencies, subject to reversion if such rating agencies withdraw the investment grade rating of Vistra Operations' senior, unsecured long-term debt securities or downgrade such rating below investment grade. The Vistra Operations Senior Secured Indenture contains 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.
Energy Harbor Revenue Bonds
Various governmental entities in Ohio and Pennsylvania have previously issued six different 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 (each such tranche, a revenue bond and collectively, the revenue bonds). Funds from the issuance of the revenue bonds were on-lent by the relevant governmental authority, as lender, to each of EHG or EHNG, as applicable, pursuant to individual loan agreements between the relevant governmental entity and EH entity (each such loan agreement, an on-lending agreement and collectively, the on-lending agreements). Under those on-lending agreements the relevant EH entity is obligated to provide contractual payments to service the principal and interest on the revenue bonds via payments on the loans. The repayment of the loans is not directly secured by the assets of the EH entities; rather such repayment is secured by a pledge of certain mortgage bonds issued by the EH entities to the relevant trustees under the respective revenue bonds. The mortgage bonds are issued by the relevant EH entity pursuant to an open-ended mortgage indenture (the base indenture), and supplemented by supplemental indentures adding the relevant tranche of mortgage bonds backing the related revenue bonds to the base indenture (as so supplemented, the mortgage indentures). The obligations under the mortgage bonds issued pursuant to the mortgage indentures are secured by substantially all assets of the EH entities, including their plants and related real estate. The obligations under mortgage indentures are cross-collateralized to each other, and provide that payments of principal and interest by the relevant EH entity under its on-lending agreement with the governmental authority constitute a dollar-for-dollar credit against the payment obligations of such EH entity under the mortgage indentures, such that the EH entities are never expected to make any payments under the bonds governed by the mortgage indentures. In the event of a default under the on-lending agreements (which are not cross-defaulted to each other), 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 under the on-lending agreements and the related mortgage indentures are guaranteed on an unsecured basis by Energy Harbor. Neither the EH entities nor Energy Harbor provides credit support for any of the debt obligations of Vistra Operations.
Vistra Operations Senior Unsecured Notes
In April 2024, Vistra Operations issued $1.0 billion aggregate principal amount of 6.875% senior unsecured notes due 2032 (6.875% Senior Unsecured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The 6.875% Senior Unsecured 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, by and among the Issuer, as borrower, Vistra Intermediate Company LLC, the guarantors party thereto, and Citibank, N.A. as administrative and collateral agent. The 6.875% Senior Secured Notes mature in April 15, 2032, with interest payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024. Net proceeds totaling approximately $990 million, together with proceeds from the April 2024 issuance of 6.000% Senior Secured Notes discussed above and cash on hand, were to be used for general corporate purposes, including to refinance outstanding indebtedness (including the senior secured debt maturities in May 2024 and July 2024). Fees and expenses related to the offering totaled $12 million and were capitalized as a reduction in the carrying amount of the debt.
Since 2018, Vistra Operations has issued and sold its senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The indentures (as may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) governing the 5.500% senior unsecured notes due 2026, the 5.625% senior unsecured notes due 2027, the 5.000% senior unsecured notes due 2027, the 4.375% senior unsecured notes due 2029, the 7.750% senior unsecured notes due 2031 and the 6.875% Senior Unsecured Notes (collectively, as each may be amended or supplemented from time to time, the Senior Unsecured Notes) provide for the full and unconditional guarantee by the Guarantor Subsidiaries of the punctual payment of the principal and interest on such notes. 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.
Other Debt Activity
Senior Secured Notes Tender Offer
In January 2024, Vistra Operations used the net proceeds from (i) the December 2023 issuances of the 6.950% senior secured notes due 2033 and 7.750% senior unsecured notes due 2031 and (ii) cash on hand, to fund a cash tender offer (Senior Secured Notes Tender Offer) to purchase for cash $759 million aggregate principal amount of certain notes, including $58 million of 4.875% senior secured notes due 2024, $345 million of 3.550% senior secured notes due 2024 and $356 million of the 5.125% senior secured notes due 2025. We recorded an extinguishment gain of $6 million on the transaction in the first quarter of 2024.
Debt Repurchase Program
In April 2024, the Board authorized the voluntary repayment or repurchase of up to $1.0 billion of outstanding debt, with such authorization expiring on December 31, 2024.
Accounts Receivable Financing
Accounts Receivable Securitization Program
TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). On April 8, 2024, the Receivables Facility was amended to increase the purchase limit from $750 million to $1.0 billion and to add Energy Harbor LLC, a direct, wholly owned subsidiary of Energy Harbor, as an Originator. The Receivables Facility was renewed and amended in July 2024, extending the term of the Receivables Facility to July 2025.
In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limit described above to fund its acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the performance of the obligations of the Originators and TXU Energy, as the servicer, under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings in the 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, 2024, outstanding borrowings under the Receivables Facility totaled $750 million and were supported by $1.645 billion of RecCo gross receivables. As of December 31, 2023, there were no outstanding borrowings under the Receivables Facility.
Repurchase Facility
TXU Energy and the other Originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2024, the Repurchase Facility was renewed until July 2025 while maintaining the facility size of $125 million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Repo Transaction). Each Repo Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.
TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the Receivables Facility.
There were no outstanding borrowings under the Repurchase Facility as of both September 30, 2024 and December 31, 2023.
10. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage our exposure to commodity price and interest rate volatility. Although we do engage in economic hedging activities to manage our exposure related to commodity price fluctuations through the use of financial and physical derivative contracts, we have no derivative positions accounted for as cash flow or fair value hedges as of September 30, 2024. All changes in the fair values of our derivative contracts, excluding contracts which are considered normal purchases and sales (NPNS), are recognized as gains or losses in the earnings of the periods in which they occur. See Note 11 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity
Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as NPNS (commodity contracts). We utilize natural gas and electricity derivatives to (i) reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets, and (ii) to hedge future purchased power costs for our retail operations. We also utilize short-term electricity, natural gas, coal, and emissions derivative instruments for fuel hedging and other purposes. 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. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in the condensed consolidated statements of operations in either operating revenues or fuel, purchased power costs and delivery fees.
Interest Rate Swaps
Interest rate swap agreements are used to reduce volatility in interest costs and related cash flows associated with our variable rate debt obligations by converting floating-rate interest to fixed rates. Unrealized gains and losses arising from changes in the fair value of the interest rate swaps as well as realized gains and losses upon settlement are reported in the condensed consolidated statements of operations in interest expense and related charges.
As of September 30, 2024, Vistra has entered into the following interest rate swaps:
| Notional Amount | Expiration Date | Rate Range (c) | ||||||||||||||||||||||||
| (in millions, except percentages) | ||||||||||||||||||||||||||
| Swapped to fixed (a) | $3,000 | July 2026 | 4.89 | % | - | 4.97% | ||||||||||||||||||||
| Swapped to variable (a) | $700 | July 2026 | 3.44 | % | - | 3.49% | ||||||||||||||||||||
| Swapped to fixed (b) | $1,625 | December 2030 | 5.20 | % | - | 5.37% |
(a)The $700 million of pay variable rate and receive fixed rate swaps match the terms of a portion of the $3.0 billion pay fixed rate and receive variable rate swaps. These matched swaps will settle over time and effectively offset the hedged position. These offsetting swaps expiring in July 2026 hedge our exposure on $2.3 billion of variable rate debt through July 2026.
(b)Effective from July 2026 through December 2030.
(c)The rate ranges reflect the fixed leg of each swap at a Term SOFR rate plus an interest margin of 2.00%.
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in the condensed consolidated balance sheets as of September 30, 2024 and December 31, 2023.
| September 30, 2024 | |||||||||||||||||||||||||||||
| Derivative Assets | Derivative Liabilities | ||||||||||||||||||||||||||||
| Commodity Contracts | Interest Rate Swaps | Commodity Contracts | Interest Rate Swaps | Total | |||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Current assets | $ | 2,826 | $ | 25 | $ | 3 | $ | — | $ | 2,854 | |||||||||||||||||||
| Noncurrent assets | 849 | 1 | 36 | — | 886 | ||||||||||||||||||||||||
| Current liabilities | (5) | — | (3,542) | (16) | (3,563) | ||||||||||||||||||||||||
| Noncurrent liabilities | (6) | — | (1,115) | (20) | (1,141) | ||||||||||||||||||||||||
| Net assets (liabilities) | $ | 3,664 | $ | 26 | $ | (4,618) | $ | (36) | $ | (964) |
| December 31, 2023 | |||||||||||||||||||||||||||||
| Derivative Assets | Derivative Liabilities | ||||||||||||||||||||||||||||
| Commodity Contracts | Interest Rate Swaps | Commodity Contracts | Interest Rate Swaps | Total | |||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Current assets | $ | 3,585 | $ | 53 | $ | 7 | $ | — | $ | 3,645 | |||||||||||||||||||
| Noncurrent assets | 565 | 11 | 1 | — | 577 | ||||||||||||||||||||||||
| Current liabilities | (1) | — | (5,233) | (24) | (5,258) | ||||||||||||||||||||||||
| Noncurrent liabilities | (5) | — | (1,659) | (24) | (1,688) | ||||||||||||||||||||||||
| Net assets (liabilities) | $ | 4,144 | $ | 64 | $ | (6,884) | $ | (48) | $ | (2,724) |
The following table presents the pre-tax realized and unrealized effect of derivative gains (losses) on net income. Amount represents changes in fair value of open positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.
| Derivative (condensed consolidated statements of operations presentation) | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Commodity contracts (Operating revenues) | $ | 1,206 | $ | (1,118) | $ | 399 | $ | (450) | |||||||||||||||
| Commodity contracts (Fuel, purchased power costs and delivery fees) | (128) | 48 | (24) | (280) | |||||||||||||||||||
| Interest rate swaps (Interest expense and related charges) | (73) | 51 | 7 | 101 | |||||||||||||||||||
| Net gain (loss) | $ | 1,005 | $ | (1,019) | $ | 382 | $ | (629) |
Balance Sheet Presentation of Derivatives
We elect to report derivative assets and liabilities in the condensed consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.
Generally, margin deposits that contractually offset these derivative instruments are reported separately in the condensed consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.
The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
| September 30, 2024 | December 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative Assets and Liabilities | Offsetting Instruments (a) | Cash Collateral (Received) Pledged (b) | Net Amounts | Derivative Assets and Liabilities | Offsetting Instruments (a) | Cash Collateral (Received) Pledged (b) | Net Amounts | |||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 3,664 | $ | (2,750) | $ | (169) | $ | 745 | $ | 4,144 | $ | (3,519) | $ | (26) | $ | 599 | ||||||||||||||||||||||||||||||||||
| Interest rate swaps | 26 | (15) | — | 11 | 64 | (28) | — | 36 | ||||||||||||||||||||||||||||||||||||||||||
| Total derivative assets | 3,690 | (2,765) | (169) | 756 | 4,208 | (3,547) | (26) | 635 | ||||||||||||||||||||||||||||||||||||||||||
| Derivative liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts | (4,618) | 2,750 | 316 | (1,552) | (6,884) | 3,519 | 970 | (2,395) | ||||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | (36) | 15 | — | (21) | (48) | 28 | — | (20) | ||||||||||||||||||||||||||||||||||||||||||
| Total derivative liabilities | (4,654) | 2,765 | 316 | (1,573) | (6,932) | 3,547 | 970 | (2,415) | ||||||||||||||||||||||||||||||||||||||||||
| Net amounts | $ | (964) | $ | — | $ | 147 | $ | (817) | $ | (2,724) | $ | — | $ | 944 | $ | (1,780) |
(a)Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b)Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and to a lesser extent, initial margin requirements.
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes, by commodity, excluding those derivatives that qualified for the NPNS scope exception, as of September 30, 2024 and December 31, 2023:
| September 30, 2024 | December 31, 2023 | |||||||||||||||||||
| Derivative type | Notional Volume | Unit of Measure | ||||||||||||||||||
| Natural gas (a) | 4,775 | 5,335 | Million MMBtu | |||||||||||||||||
| Electricity | 786,155 | 800,001 | GWh | |||||||||||||||||
| Financial transmission rights (b) | 243,755 | 250,895 | GWh | |||||||||||||||||
| Coal | 33 | 35 | Million U.S. tons | |||||||||||||||||
| Fuel oil | 16 | 3 | Million gallons | |||||||||||||||||
| Emissions | 62 | 24 | Million U.S. tons | |||||||||||||||||
| Renewable energy certificates | 28 | 29 | Million certificates | |||||||||||||||||
| Interest rate swaps – variable/fixed (c) | $ | 4,625 | $ | 5,225 | Million U.S. dollars | |||||||||||||||
| Interest rate swaps – fixed/variable (c) | $ | 700 | $ | 1,300 | Million U.S. dollars |
(a)Represents gross notional forward sales, purchases and options transaction, locational basis swaps and other natural gas transactions.
(b)Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions.
(c)Includes notional amounts of interest rate swaps with maturity dates varying between July 2026 through December 2030.
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, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Fair value of derivative contract liabilities (a) | $ | (1,369) | $ | (1,890) | |||||||
| Offsetting fair value under netting arrangements (b) | 720 | 692 | |||||||||
| Cash collateral and letters of credit | 441 | 854 | |||||||||
| Liquidity exposure | $ | (208) | $ | (344) |
____________
(a)Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).
(b)Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. As of September 30, 2024, total credit risk exposure to all counterparties related to derivative contracts totaled $4.077 billion (including associated accounts receivable). The net exposure to those counterparties totaled $827 million as of September 30, 2024, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure from any single counterparty totaling $250 million. As of September 30, 2024, the credit risk exposure to the banking and financial sector represented 75% of the total credit risk exposure and 25% of the net exposure.
This concentration of credit risk increases the risk that a default by any of our counterparties could have a material effect on our financial condition, results of operations and liquidity. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation procedures including, but not limited to, (i) requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our counterparties that allow for netting of positive and negative exposures, and that detail credit enhancements (such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits) required in the event of a material downgrade in their credit rating.
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, 2024 | December 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Reclass (a) | Total | Level 1 | Level 2 | Level 3 | Reclass (a) | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts (b) | $ | 2,205 | $ | 464 | $ | 995 | $ | 50 | $ | 3,714 | $ | 2,886 | $ | 628 | $ | 630 | $ | 14 | $ | 4,158 | |||||||||||||||||||||||||||||||||||||||
| Interest rate swaps (b) | — | 26 | — | — | 26 | — | 64 | — | — | 64 | |||||||||||||||||||||||||||||||||||||||||||||||||
| NDTs – equity securities (c) (d) | 1,537 | — | — | 1,537 | 638 | — | — | 638 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| NDTs – debt securities (c) (e) | 74 | 2,031 | — | 2,105 | — | 734 | — | 734 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Sub-total | $ | 3,816 | $ | 2,521 | $ | 995 | $ | 50 | 7,382 | $ | 3,524 | $ | 1,426 | $ | 630 | $ | 14 | 5,594 | |||||||||||||||||||||||||||||||||||||||||
| Assets measured at net asset value (f): | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NDTs – equity securities (c) (d) (f) | 802 | 579 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 8,184 | $ | 6,173 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 2,359 | $ | 747 | $ | 1,512 | $ | 50 | $ | 4,668 | $ | 3,815 | $ | 1,395 | $ | 1,674 | $ | 14 | $ | 6,898 | |||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | — | 36 | — | — | 36 | — | 48 | — | — | 48 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | $ | 2,359 | $ | 783 | $ | 1,512 | $ | 50 | $ | 4,704 | $ | 3,815 | $ | 1,443 | $ | 1,674 | $ | 14 | $ | 6,946 |
(a)Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability position. This reclassification represents the adjustment needed to reconcile to the gross amounts presented on the condensed consolidated balance sheets.
(b)See Note 10 for definitions of commodity contracts and interest rate swaps.
(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.
(d)The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments.
(e)The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt securities are weighted with government and investment grade corporate bonds. Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 3.96% and 3.19% as of September 30, 2024 and December 31, 2023, respectively, and an average maturity of 8 years and 11 years as of both September 30, 2024 and December 31, 2023. NDT debt securities held as of September 30, 2024 mature as follows: $1.011 billion in one to five years, $616 million in five to 10 years and $478 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 the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of September 30, 2024 and December 31, 2023:
| September 30, 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 | $ | 773 | $ | (1,235) | $ | (462) | Income Approach | Hourly price curve shape (c) | $— | to | $95 | $48 | ||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Illiquid delivery periods for hub power prices and Heat Rates (d) | $20 | to | $115 | $68 | ||||||||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Options | 11 | (173) | (162) | Option Pricing Model | Natural gas to power correlation (e) | 10% | to | 100% | 55% | |||||||||||||||||||||||||||||||||||||||||
| Power and natural gas volatility (e) | 5% | to | 710% | 359% | ||||||||||||||||||||||||||||||||||||||||||||||
| Financial transmission rights/Congestion revenue rights | 176 | (32) | 144 | Market Approach (f) | Illiquid price differences between settlement points (g) | $(35) | to | $20 | $(7) | |||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 23 | (65) | (42) | Income Approach | Natural gas basis (h) | $— | to | $10 | $4 | |||||||||||||||||||||||||||||||||||||||||
| MMBtu | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Illiquid delivery periods (i) | $— | to | $5 | $4 | ||||||||||||||||||||||||||||||||||||||||||||||
| MMBtu | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other (j) | 12 | (7) | 5 | |||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 995 | $ | (1,512) | $ | (517) |
| December 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Contract Type (a) | Assets | Liabilities | Total, Net | Valuation Technique | Significant Unobservable Input | Range (b) | Average (b) | |||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Electricity purchases and sales | $ | 449 | $ | (1,273) | $ | (824) | Income Approach | Hourly price curve shape (c) | $— | to | $85 | $44 | ||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Illiquid delivery periods for hub power prices and Heat Rates (d) | $30 | to | $110 | $71 | ||||||||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Options | 1 | (237) | (236) | Option Pricing Model | Natural gas to power correlation (e) | 10% | to | 100% | 55% | |||||||||||||||||||||||||||||||||||||||||
| Power and natural gas volatility (e) | 10% | to | 870% | 441% | ||||||||||||||||||||||||||||||||||||||||||||||
| Financial transmission rights/Congestion revenue rights | 157 | (34) | 123 | Market Approach (f) | Illiquid price differences between settlement points (g) | $(85) | to | $25 | $(30) | |||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 9 | (112) | (103) | Income Approach | Natural gas basis (h) | $— | to | $15 | $6 | |||||||||||||||||||||||||||||||||||||||||
| MMBtu | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Illiquid delivery periods (i) | $— | to | $5 | $4 | ||||||||||||||||||||||||||||||||||||||||||||||
| MMBtu | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other (j) | 14 | (18) | (4) | |||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 630 | $ | (1,674) | $ | (1,044) |
(a)(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 the Level 3 assets and liabilities. All Level 3 assets and liabilities are commodity contracts, therefore, substantially all changes in fair value detailed below are reported as Operating Revenues in the condensed consolidated statements of operations:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Net liability balance at beginning of period | $ | (1,104) | $ | (1,120) | $ | (1,044) | $ | (1,219) | |||||||||||||||
| Total unrealized valuation gains (losses) | 482 | (548) | 194 | (498) | |||||||||||||||||||
| Purchases, issuances and settlements (a): | |||||||||||||||||||||||
| Purchases | 62 | 53 | 193 | 153 | |||||||||||||||||||
| Issuances | (7) | (6) | (24) | (19) | |||||||||||||||||||
| Settlements | 57 | 158 | 196 | 120 | |||||||||||||||||||
| Transfers into Level 3 (b) | 5 | (38) | (15) | (50) | |||||||||||||||||||
| Transfers out of Level 3 (b) | (12) | 217 | (4) | 229 | |||||||||||||||||||
| Net liabilities assumed in connection with the Energy Harbor Merger | — | — | (13) | — | |||||||||||||||||||
| Net change | 587 | (164) | 527 | (65) | |||||||||||||||||||
| Net liability balance at end of period | $ | (517) | $ | (1,284) | $ | (517) | $ | (1,284) | |||||||||||||||
| Unrealized valuation gains (losses) relating to instruments held at end of period | $ | 361 | $ | (486) | $ | (114) | $ | (734) |
(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, 2024, transfers into Level 3 primarily consist of natural gas derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power derivatives where forward pricing inputs have become observable. 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 power and natural gas derivatives where forward pricing inputs have become observable. For the three months ended September 30, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power derivatives where forward pricing inputs have become observable. For the nine months ended September 30, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable.
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.
12. TAX RECEIVABLE AGREEMENT OBLIGATION
On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH, whereby we issued TRA rights to these former first-lien creditors of TCEH entitled to receive them under the Plan of Reorganization (TRA Rights). The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a result of (i) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (ii) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.
Vistra began a series of repurchases of TRA Rights (Repurchase) from certain registered holders of the TRA Rights (Selling Holders) in December 2023. In connection with the Repurchase, holders of approximately 74% of the outstanding TRA Rights consented to certain amendments to the TRA which were effected in an Amended and Restated Tax Receivables Agreement (A&R TRA), dated as of December 29, 2023. Such amendments to the TRA included (i) the removal of the Company's obligation to provide registered holders of the TRA Rights (Holders) with regular reporting and access to information, (ii) limitations on the transferability of the TRA Rights, (iii) removal of certain obligations of the Company in the event it incurs indebtedness and (iv) a change to the definition of "Change of Control."
The following table details our repurchases of TRA Rights during the periods indicated:
| Number of TRA Rights | ||||||||
| TRA Rights issued on the Effective Date and outstanding as of January 1, 2023 and March 31, 2023 | 426,369,370 | |||||||
| The December 31, 2023 Repurchase (a) | (317,387,412) | |||||||
| TRA Rights outstanding as of January 1, 2024 | 108,981,958 | |||||||
| The January 11, 2024 Repurchase (b) | (43,494,944) | |||||||
| The February 13, 2024 Repurchase (c) | (55,056,931) | |||||||
| The February 28, 2024 Repurchase (c) | (2,235,020) | |||||||
| Other repurchases | (161,274) | |||||||
| TRA Rights outstanding as of September 30, 2024 (d) | 8,033,789 |
(a)On December 31, 2023, we repurchased TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $476 million. The consideration for the December 31, 2023 Repurchase was conveyed through the issuance of 476,081 shares of Vistra Series C Preferred Stock to the Selling Holders.
(b)On January 11, 2024, we repurchased TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $65 million using cash on hand.
(c)On January 31, 2024, we announced a cash tender offer to purchase any and all outstanding TRA Rights in exchange for consideration of $1.50 per tendered TRA Right accepted for purchase prior to close of business of February 13, 2024 (Early Tender Date), which included an early tender premium of $0.05 per TRA Right accepted for purchase. On the Early Tender Date the Company repurchased TRA Rights in exchange for total consideration of $83 million and on February 28, 2024 additional TRA Rights were repurchased under the cash tender offer for total consideration of $3 million or $1.45 per TRA Right accepted for purchase.
(d)Represents TRA Rights outstanding following Repurchases of an aggregate of 98% of the TRA Rights initially issued upon Emergence.
The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in the condensed consolidated balance sheets:
| Nine Months Ended September 30, | |||||||||||
| 2024 | 2023 | ||||||||||
| (in millions) | |||||||||||
| TRA obligation at the beginning of the period | $ | 171 | $ | 522 | |||||||
| Accretion expense | 6 | 62 | |||||||||
| Changes in tax assumptions impacting timing of payments | (1) | 66 | |||||||||
| Impacts of Tax Receivable Agreement | 5 | 128 | |||||||||
| Repurchase/tender of TRA Rights | (161) | — | |||||||||
| TRA obligation at the end of the period | 15 | 650 | |||||||||
| Less amounts due currently | — | (10) | |||||||||
| Noncurrent TRA obligation at the end of the period | $ | 15 | $ | 640 |
13. ASSET RETIREMENT OBLIGATIONS
Our asset retirement obligations (ARO) primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs. AROs are based on legal obligations associated with enacted law, regulatory, or contractual retirement requirements for which decommissioning timing and cost estimates are reasonably estimable. See Note 14 for a discussion of proposed and final regulations which could result in additional AROs if enacted as proposed and/or if decommissioning timing and cost estimates are revised based on potential applicability of the rules.
The following table summarizes the changes to our current and noncurrent ARO liabilities:
| Nine Months Ended September 30, 2024 | Nine Months Ended September 30, 2023 | ||||||||||||||||||||||||||||||||||
| 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 | $ | 1,742 | $ | 796 | $ | 2,538 | $ | 1,688 | $ | 749 | $ | 2,437 | |||||||||||||||||||||||
| Additions: | |||||||||||||||||||||||||||||||||||
| Accretion (a) | 95 | 31 | 126 | 40 | 26 | 66 | |||||||||||||||||||||||||||||
| Adjustment for change in estimates | — | 18 | 18 | — | 30 | 30 | |||||||||||||||||||||||||||||
| Adjustment for obligations assumed through acquisition | 1,368 | — | 1,368 | — | — | — | |||||||||||||||||||||||||||||
| Reductions: | |||||||||||||||||||||||||||||||||||
| Payments | — | (64) | (64) | — | (60) | (60) | |||||||||||||||||||||||||||||
| Liability at end of period | 3,205 | 781 | 3,986 | 1,728 | 745 | 2,473 | |||||||||||||||||||||||||||||
| Less amounts due currently | — | (102) | (102) | — | (123) | (123) | |||||||||||||||||||||||||||||
| Noncurrent liability at end of period | $ | 3,205 | $ | 679 | $ | 3,884 | $ | 1,728 | $ | 622 | $ | 2,350 |
(a)For the nine months ended September 30, 2024, nuclear plant decommissioning accretion includes $53 million of accretion expense recognized in operating costs in the condensed consolidated statements of operations and $42 million reflected as a change in regulatory liability in the condensed consolidated balance sheets. For the nine months ended September 30, 2023, nuclear plant decommissioning accretion reflected as a change in regulatory liability in the condensed consolidated balance sheets.
Nuclear Decommissioning AROs
AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and the facilities acquired from Energy Harbor which include the Beaver Valley, Perry and Davis-Besse plants in PJM (the PJM nuclear facilities). To estimate our nuclear decommissioning obligations we use a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates.
As of September 30, 2024, the carrying value of our ARO related to our Comanche Peak plant decommissioning estimate totaled $1.783 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.253 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $470 million that has been 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.
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.
14. 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, 2024, we had outstanding letters of credit totaling $2.380 billion as follows:
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$2.013 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;
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$227 million to support battery and solar development projects;
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$25 million to support executory contracts and insurance agreements;
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$95 million to support our REP financial requirements with the PUCT; and
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$20 million for other credit support requirements.
Surety Bonds
As of September 30, 2024, we had outstanding surety bonds totaling $1.464 billion to support performance under various contracts and legal obligations in the normal course of business.
Litigation and Regulatory Proceedings
Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material.
Litigation
Natural Gas Index Pricing Litigation — We, through our subsidiaries, and another company remain named as defendants in one consolidated putative class action lawsuit pending in federal court in Wisconsin claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes. In April 2023, the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit Court) heard oral argument on an interlocutory appeal challenging the district court's order certifying a class.
Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius 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 5-year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint.
Ohio House Bill 6 ("HB6") — In July 2019, Ohio adopted a law referred to as HB6, which, among other things, provided subsidies for two nuclear power plants which we acquired in March 2024 upon the closing of our merger with Energy Harbor. We had opposed enactment of that subsidy legislation at the time, and the nuclear subsidies were repealed in 2021 prior to any subsidies being distributed. The U.S. Attorney's Office conducted an investigation into the activities related to the passage of HB6, and Energy Harbor received a grand jury subpoena in July 2020 requiring production of certain information related to that investigation. Energy Harbor completed its responses to that subpoena by December 2021. In August 2020, the Ohio Attorney General filed a civil Racketeer Influenced and Corrupt Organizations Act (RICO) complaint against FirstEnergy Corp. and various Energy Harbor companies related to passage of HB6 (State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al., Franklin County, Ohio Common Pleas Court Case No. 20CV006281 and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. Energy Harbor Corp., et al., Franklin County, Ohio Common Pleas Court Case No. 20CV007386). Motions to dismiss those cases remain pending and the case is currently stayed.
Winter Storm Uri Legal Proceedings
Repricing Challenges — In March 2021, we filed an appeal in the Third Court of Appeals in Austin, Texas (Third Court of Appeals), challenging the PUCT's February 15 and February 16, 2021 orders governing ERCOT's determination of wholesale power prices during load-shedding events. Other parties also supported our challenge to the PUCT's orders. In March 2023, the Third Court of Appeals issued a unanimous decision and agreed with our arguments that the PUCT's pricing orders constituted de facto competition rules and exceeded the PUCT's statutory authority. The Third Court of Appeals vacated the pricing orders and remanded the matter to the PUCT for further proceedings. In March 2023, the PUCT appealed the Third Court of Appeals' ruling to the Texas Supreme Court. In September 2023, the Texas Supreme Court granted the PUC and its intervenors petitions for review of the Third Court of Appeals' decision and the Court heard oral argument in January 2024. In June 2024, the Texas Supreme Court issued a decision reversing the Third Court of Appeals and finding that the pricing orders were lawful.
Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, the Texas Attorney General, the FERC and the NRC initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges for generators arising from the event, including performance and fuel and supply issues. We responded to all those investigatory requests. In addition, a large number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been, and continue to be, filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. We and other defendants requested that all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL) pretrial judge. In June 2021, the MDL panel granted the request to consolidate all these cases into an MDL for pretrial proceedings. Additional personal injury cases that have been, and continue to be, filed on behalf of additional plaintiffs have been consolidated with the MDL proceedings. In addition, in January 2022, an insurance subrogation lawsuit was filed in Austin state court by over one hundred insurance companies against ERCOT, Vistra and several other defendants. The lawsuit seeks recovery of insurance funds paid out by these insurance companies to various policyholders for claims related to Winter Storm Uri, and that case has also now been consolidated with the MDL proceedings. In the summer of 2022, various defendant groups filed motions to dismiss five so-called bellwether cases, and the MDL court heard oral argument on those motions in October 2022. In January 2023, the MDL court ruled on the various motions to dismiss and denied the motions to dismiss of the generator defendants and the transmission distribution utilities defendants, but granted the motions of some of the other defendant groups, including the retail electric providers and ERCOT. In February 2023, the generator defendants filed a mandamus petition with the First Court of Appeals in Houston, Texas (First Court of Appeals) to review the MDL court's denial of the motion to dismiss. In December 2023, the First Court of Appeals in a unanimous decision granted our mandamus petition and instructed the MDL court to grant the motions to dismiss in full filed by the generator defendants. In January 2024, the plaintiffs filed a request with the full Court of Appeals to review that panel ruling. We believe we have strong defenses to these lawsuits and intend to defend against these cases vigorously.
Greenhouse Gas Emissions (GHG)
In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing. Starting in 2030, the rule would begin to require more CO2 emissions control at certain existing fossil fuel-fired steam generating units, with more stringent standards beginning in 2032 for coal-fired units that plan to operate for a longer period of time. For new natural gas combustion turbines that operate more frequently, the rule would phase in increasingly stringent CO2 requirements over time. Under the rule, states would be required to submit plans to the EPA within 24 months of the rule's publication in the Federal Register that provide for the establishment, implementation, and enforcement of standards of performance for existing sources. These state plans must generally establish standards that are at least as stringent as the EPA's emission guidelines. Under the rule, existing coal-fired steam generation units that will operate on or after January 1, 2039 must start complying with their standards of performance (based on application of CCS with 90 percent capture) by January 1, 2032. Units that are permanently retiring before January 1, 2039, but after December 31, 2031, must start complying with their standards of performance (based on co-firing with 40 percent natural gas on a heat input basis) beginning on January 1, 2030. Units permanently retiring by January 1, 2032 are exempt from the rule. Given our previously announced coal unit retirement commitments, our Martin Lake and Oak Grove plants are the only coal units that are subject to this rule. Our Graham, Lake Hubbard, Stryker Creek and Trinidad oil/natural gas facilities are also regulated under this rule. None of our existing large or small combustion turbines are subject to this rule. The rule also regulates any new gas units. For new combustion turbine units, the rule establishes three different categories depending on how intensively those units are operated, with immediate compliance obligations for all three categories but more stringent standards beginning in 2032 only for the category of units operating the most intensively. Following finalization of the rule in May 2024, 17 petitions for review from various states, industry groups and companies were filed in the D.C. Circuit Court along with multiple motions to stay the rule. We are participating in an industry coalition challenging the rule. In July 2024, the D.C. Circuit Court denied the motions to stay and a number of parties subsequently filed an emergency request with the U.S. Supreme Court to stay the rule which was denied in October 2024. Oral argument on the merits of the legal challenges to the rule will be held in December 2024 before the D.C. Circuit Court.
Cross-State Air Pollution Rule (CSAPR) and Good Neighbor Plan
In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to lower the 8-hour standard for ozone emissions during ozone season (May to September). As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS. In February 2023, the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain trade groups, and others challenged that disapproval in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). In March 2023, those same parties filed motions to stay the EPA's SIP disapproval in the Fifth Circuit Court, and the EPA moved to transfer our challenges to the D.C. Circuit Court or have those challenges dismissed.
In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS. We, along with many other companies, trade groups, states and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions. In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP). The FIP applied to 22 states beginning with the 2023 ozone seasons. States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia and West Virginia. Texas would be moved into the revised (and more restrictive) Group 3 trading program previously established in the Revised CSAPR Update Rule that includes emission budgets for 2023 that the EPA says are achievable through existing controls installed at power plants. Allowances will be limited under the program and will be further reduced beginning in ozone season 2026 to a level that is intended to reduce operating time of coal-fueled power plants during ozone season or force coal plants to retire, particularly those that do not have selective catalytic reduction systems such as our Martin Lake power plant.
In May 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a decision on the merits and denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. As a result of the stay, we do not believe the EPA has authority to implement the GNP FIP as to Texas sources pending the resolution of the merits, meaning that Texas will remain in Group 2 and not be subject to any requirements under the GNP FIP at least until the Fifth Circuit Court rules on the merits. Oral argument was heard in December 2023 before the Fifth Circuit Court. In June 2023, the EPA published the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the Fifth Circuit Court. In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the GNP FIP in the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court. After the motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the GNP FIP as to Texas is stayed. In July 2023, the Fifth Circuit Court ruled that the GNP FIP challenge would be held in abeyance pending the resolution of the litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay. In a related action brought by other states and parties challenging the GNP FIP, in June 2024, the U.S. Supreme Court granted a stay of the GNP FIP pending a review of the merits by the D.C. Circuit Court and any further appeal to the U.S. Supreme Court. As a result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP.
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. The program includes 39 generation units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. For NOX, the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas' SIP that determines that no electricity generation units are subject to BART for particulate matter. In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit Court, where we have intervened in support of the EPA. We are in compliance with the rule, and the retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply. The EPA is in the process of reconsidering the BART rule, and the challenges in the D.C. Circuit Court have been held in abeyance pending the EPA's final action on reconsideration. In May 2023, a proposed BART rule was published in the Federal Register that would withdraw the trading program provisions of the prior rule and would establish SO2 limits on six facilities in Texas, including Martin Lake and Coleto Creek. Under the current proposal, compliance would be required within 3 years for Martin Lake and 5 years for Coleto Creek. Due to the announced shutdown for Coleto Creek, we do not anticipate any impacts at that facility, and we are evaluating potential compliance options at Martin Lake should this proposal become final. We submitted comments to the EPA on this proposal in August 2023.
SO****2 Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable. In May 2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring data supporting an attainment designation. In June 2021, the EPA published two notices; one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations. We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, and this case was argued before the Fifth Circuit Court in July 2022. In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO2 emissions from the plant. The proposed agreed order associated with the SIP proposal reduces emission limits as of January 2022. Emission reductions required are those necessary to demonstrate attainment with the NAAQS. The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval. In January 2024, in a split decision, the Fifth Circuit Court denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO2 for the area around Martin Lake. As a result of this decision the EPA's nonattainment designation - originally made in 2016 - remains in place. We anticipate the EPA will likely move forward with either proposing a federal plan for the area in light of an approved consent decree, between the Sierra Club and the EPA that requires the EPA taking final action promulgating a FIP for the nonattainment area by December 13, 2024, or the EPA may approve Texas' SIP submittal discussed above. In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January 2024.
Particulate Matter
In February 2024, the EPA issued a rule addressing the annual health-based national ambient air quality standards for fine particulate matter (or PM2.5). In general, the rule lowers the level of the annual PM2.5 standard from 12.0 micrograms per cubic meter (µg/m3) to 9.0 µg/m3. The effective date of the rule is 60 days from publication in the Federal Register, and the earliest attainment date for areas exceeding the new standard is 2032. Based on 2020-2022 design value associated with the rule, we have just five plants (Oakland (California), Calumet (Illinois), Liberty (Pennsylvania), Miami Fort (Ohio) and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard. We have previously announced that our Miami Fort generation facility will close by the end of 2027. States will have to develop a plan (by late 2027 at the earliest) to get those areas into attainment and there would be a possibility that additional controls would be required for those sites. However, before the state begins this planning process, the designation process will occur within two years from the issuance of the final rule. The states develop recommendations about the boundaries of the nonattainment counties and the EPA must finalize the designations including the boundaries of each nonattainment area.
Effluent Limitation Guidelines (ELGs)
In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. The EPA published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Notifications were made to Texas, Illinois and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. In May 2024, the EPA published the final ELG rule revisions, which contains new requirements for legacy wastewater and combustion residual leachate. The final rule also leaves in place the subcategory for facilities that permanently cease coal combustion by 2028. We are reviewing the rule for impact but believe it will require additional treatment costs for legacy wastewaters during pond closure activities and combustion residual leachate. At this time, we don't expect the impact of these additional treatment costs to be material. A number of parties have since challenged the rule and that case is pending in the U.S. Court of Appeals for the Eighth Circuit. We are not a party to that litigation.
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.
In addition, in January 2022, the EPA also made a series of public statements, including in a press release, that purported to impose new, more onerous closure requirements for CCR units. In April 2022, we, along with the Utility Solid Waste Activities Group (USWAG), a trade association of over 130 utility operating companies, energy companies, and certain other industry associations, filed petitions for review with the D.C. Circuit Court and asked the court to determine that the EPA cannot implement or enforce the new purported requirements because the EPA has not followed the required procedures. The State of Texas and the TCEQ intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various environmental groups have intervened on behalf of the EPA. In June 2024, the D.C. Circuit Court dismissed the petitions filed challenging the EPA's January 2022 statements because it found the statements did not amend the existing CCR regulations, and thus the D.C. Circuit Court did not have jurisdiction to review them.
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 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.
MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility.
At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the Illinois Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash. These proposed closure costs are reflected in the ARO in the condensed consolidated balance sheets (see Note 17).
In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule.
In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of guidelines, rules and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal at any site. In May 2021, we, along with other industry petitioners, filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule. In March 2024, the Illinois Fourth Judicial District issued a decision denying the industry petitions. We do not anticipate any impacts from this decision. In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in January 2022 and five of our sites in July 2022. One additional closure construction application was filed for our Baldwin facility in August 2023.
For all of the above 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 then existing closure requirements, and is reasonably possible 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
In May 2015, three complaints were filed at the FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by the Complainants. We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff in connection with the PRA and disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at the FERC against MISO in June 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint with respect to Dynegy's conduct alleged in the complaint.
In October 2015, the FERC issued an order of nonpublic, formal investigation (the investigation) into whether market manipulation or other potential violations of the FERC orders, rules and regulations occurred before or during the PRA.
In December 2015, the FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction. The order did not address the arguments of the Complainants regarding the PRA and stated that those issues remained under consideration and would be addressed in a future order.
In July 2019, the FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed. The FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff. A request for rehearing was denied by the FERC in March 2020. The order was appealed by Public Citizen, Inc. to the D.C. Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing Company intervened in the case in June 2020. In August 2021, the D.C. Circuit Court issued a ruling denying Public Citizen, Inc.'s arguments that the FERC failed to meet its obligation to ensure just and reasonable rates because it did not review the prices resulting from the auction before those prices went into effect and that the FERC was arbitrary and capricious in failing to adequately explain its decision to close its investigation into whether Dynegy engaged in market manipulation. The D.C. Circuit Court of Appeals granted Public Citizen, Inc.'s petition in part finding that the FERC's decision that the auction results were just and reasonable solely because the auction process complied with the filed tariff was unreasoned and remanded the case back to the FERC for further proceedings on that issue. On February 4, 2022 the Illinois Attorney General and Public Citizen, Inc. filed a motion at the FERC requesting that the FERC on remand reverse its prior decision and either find that auction results were not just and reasonable and order Dynegy to pay refunds to Illinois or, in the alternative, initiate an evidentiary hearing and discovery. We filed a response to this motion and will continue to vigorously defend our position. In June 2022, the FERC issued an order on remand establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 planning resource auction. Although the FERC directed the Office of Enforcement to file a remand report, the FERC stated in the June 2022 order that it is not reopening the Office of Enforcement investigation. In September 2022, the Office of Enforcement filed its remand report stating that the Office of Enforcement staff found during its investigation that Dynegy knowingly engaged in manipulative behavior to set the Zone 4 price in the 2015-2016 PRA. In June 2023, the Company filed its initial brief and response to the remand report, and in August 2023 the Company filed a reply to the initial briefs from other parties. In June 2024, the FERC issued an order for an evidentiary hearing (or a trial before a FERC administrative law judge) to determine what the FERC cited as "disputed issues of material fact" that it believes cannot be resolved on the existing record and, in October 2024, issued an order dismissing our request for rehearing of the June 2024 order. We will continue to vigorously defend our position.
Other Matters
We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
Nuclear Insurance
Nuclear insurance includes nuclear liability coverage, property damage, nuclear accident decontamination and accidental premature decommissioning coverage and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity or financial condition.
With regard to nuclear liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $16.2 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $16.2 billion limit for a single incident. As required, we insure against a possible nuclear incident at our nuclear facilities resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP).
Under the SFP, in the event of any single nuclear liability loss in excess of $500 million at any nuclear generation facility in the U.S., each operating licensed reactor in the U.S. is subject to an assessment of up to $165.9 million. This approximately $165.9 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur by November 2028. Assessments are currently limited to $24.7 million per operating licensed reactor per year per incident. As of September 30, 2024, our maximum potential assessment under the industry retrospective plan would be approximately $995.4 million per incident but no more than $148.2 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $500 million per accident at any nuclear facility.
The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $1.06 billion of nuclear accident decontamination and reactor damage stabilization insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance for our Comanche Peak facility in the amount of $2.25 billion and non-nuclear accident related property damage in the amount of $1.0 billion (subject to a $5 million deductible per accident except for natural hazards which are subject to a $9.5 million deductible per accident), and losses excluded or above such limits are self-insured. We maintain nuclear accident decontamination and reactor damage stabilization insurance and non-nuclear accident related property damage for our Beaver Valley, Davis-Besse and Perry facilities in the amount of $1.5 billion each (subject to a $20 million deductible per accident), and losses excluded or above such limits are self-insured.
We also maintain Accidental Outage insurance to help cover the additional costs of obtaining replacement electricity from another source if the units are out of service for more than twelve weeks as a result of covered direct physical damage. Coverage at Comanche Peak provides for weekly payments per unit up to $4.5 million for the first 52 weeks and up to $2.7 million for a remaining 21 weeks for non-nuclear and up to $3.6 million for a remaining 71 weeks for nuclear property damage outages. The total maximum coverage is $291 million for non-nuclear property damage and $490 million for nuclear property damage outages. Coverage at Beaver Valley, Davis-Besse and Perry facilities provide for weekly payments per unit up to $2.5 million for the first 52 weeks and up to $1.5 million for a remaining 52 weeks for non-nuclear and up to $2 million for a remaining 110 weeks for nuclear property damage outages. The total maximum coverage is $208 million for non-nuclear property damage and $350 million for nuclear damage outages. There are two units at Comanche Peak and Beaver Valley, and coverage amounts applicable to each unit will reduce to 80% if both units are out of service at the same time as a result of the same accident.
15. EQUITY
Share Repurchase Program
In October 2021, we announced that the Board authorized a share repurchase program (Share Repurchase Program). Under the Share Repurchase Program, shares of the Company's common stock may be repurchased in open-market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Exchange Act, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the certificates of designation of the Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock, respectively.
The initial authorization (effective on October 11, 2021) of the Share Repurchase Program allowed for the repurchase of up to $2.0 billion of our outstanding shares of common stock. In August 2022, March 2023 and February 2024, the Board authorized incremental amounts of $1.25 billion, $1.0 billion and $1.5 billion, respectively. As of September 30, 2024 $5.75 billion of our common stock has been authorized for repurchase under our Share Repurchase Program of which approximately $1.236 billion was available for additional repurchases under the Share Repurchase Program. In October 2024, the Board authorized an incremental amount of $1.0 billion.
In the three months ended September 30, 2024, 4,849,061 shares of our common stock were repurchased for approximately $402 million at an average price of $82.90 per share of common stock. In the nine months ended September 30, 2024, 14,934,631 shares of our common stock were repurchased for approximately $1.014 billion at an average price of $67.92 per share of common stock. Shares repurchased include 52,833 of unsettled shares for $6 million as of September 30, 2024.
In the three months ended September 30, 2023, 10,550,307 shares of our common stock were repurchased for approximately $320 million at an average price of $30.36 per share of common stock. In the nine months ended September 30, 2023, 34,003,663 shares of our common stock were repurchased for approximately $875 million at an average price of $25.74 per share of common stock.
Preferred Stock
The Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock are not convertible into or exchangeable for any other securities of the Company and have limited voting rights.
Series A Preferred Stock
The Series A Preferred Stock may be redeemed at the option of the Company at any time after October 15, 2026 (Series A First Reset Date) and in certain other circumstances prior to the Series A First Reset Date.
The annual dividend rate on each share of Series A Preferred Stock is 8.0% of the liquidation preference from the issuance date (October 15, 2021) to, but excluding, the Series A First Reset Date. On and after the Series A First Reset Date, the dividend rate on each share of Series A Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.07%), plus a spread of 6.93% per annum. The Series A Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each April 15 and October 15, commencing on April 15, 2022, when, as and if declared by the Board.
Series B Preferred Stock
The Series B Preferred Stock may be redeemed at the option of the Company at any time after December 15, 2026 (Series B First Reset Date) and in certain other circumstances prior to the Series B First Reset Date.
The annual dividend rate on each share of Series B Preferred Stock is 7.0% of liquidation preference from the issuance date (December 10, 2021) to, but excluding, the Series B First Reset Date. On and after the Series B First Reset Date, the dividend rate on each share of Series B Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.26%), plus a spread of 5.74% per annum. The Series B Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series B Preferred Stock are payable semiannually, in arrears, on each June 15 and December 15, commencing on June 15, 2022, when, as and if declared by the Board.
Series C Preferred Stock
The Series C Preferred Stock may be redeemed at the option of the Company at any time after January 15, 2029 (Series C First Reset Date) and in certain other circumstances prior to the Series C First Reset Date.
The annual dividend rate on each share of Series C Preferred Stock is 8.875% of liquidation preference from the issuance date (December 29, 2023) to, but excluding, the Series C First Reset Date. On and after the Series C First Reset Date, the dividend rate on each share of Series C Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 3.83%), plus a spread of 5.045% per annum. The Series C Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series C Preferred Stock are payable semiannually, in arrears, on each July 15 and January 15, commencing on July 15, 2024, when, as and if declared by the Board.
Dividends
Common Stock Dividends
In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations. Quarterly dividends paid per share of common stock in 2024 and 2023 are reflected in the table below.
| Nine Months Ended September 30, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||||||||||||
| Board Declaration Date | Payment Date | Per Share Amount | Board Declaration Date | Payment Date | Per Share Amount | |||||||||||||||||||||||||||
| February 2024 | March 2024 | $ | 0.2150 | February 2023 | March 2023 | $ | 0.1975 | |||||||||||||||||||||||||
| May 2024 | June 2024 | $ | 0.2175 | May 2023 | June 2023 | $ | 0.2040 | |||||||||||||||||||||||||
| July 2024 | September 2024 | $ | 0.2195 | August 2023 | September 2023 | $ | 0.2060 | |||||||||||||||||||||||||
| November 2023 | December 2023 | $ | 0.2130 |
In October 2024, the Board declared a quarterly dividend of $0.2215 per share of common stock that will be paid in December 2024.
Preferred Stock Dividends
Semiannual dividends paid per share of each respective preferred stock series in 2024 and 2023 are reflected in the table below. Dividends payable are recorded on the Board declaration date.
| Nine Months Ended September 30, 2024 | Year Ended December 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Board Declaration Date | Payment Date | Per Share Amount | Board Declaration Date | Payment Date | Per Share Amount | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Series A Preferred Stock: | Series A Preferred Stock: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| February 2024 | April 2024 | $ | 40.00 | February 2023 | April 2023 | $ | 40.00 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| August 2023 | October 2023 | $ | 40.00 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Series B Preferred Stock: | Series B Preferred Stock: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| May 2024 | June 2024 | $ | 35.00 | May 2023 | June 2023 | $ | 35.00 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| November 2023 | December 2023 | $ | 35.00 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Series C Preferred Stock: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| May 2024 | July 2024 | $ | 48.32 |
In July 2024, the Board declared a semi-annual dividend of $40.00 per share on Series A Preferred Stock that was paid in October 2024. In October 2024, the Board declared (i) a semi-annual dividend of $35.00 per share on Series B Preferred Stock that will be paid in December 2024 and (ii) a semi-annual dividend of $44.375 per share on the Series C Preferred Stock that will be paid in January 2025.
Dividend Restrictions
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, 2024, Vistra Operations can distribute approximately $6.8 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 $515 million and $280 million for the three months ended September 30, 2024 and 2023, respectively, and $1.505 billion and $1.055 billion for the nine months ended September 30, 2024 and 2023, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of September 30, 2024, all of the restricted net assets of Vistra Operations may be distributed to Parent.
In addition to the restrictions under the Vistra Operations Credit Agreement, under applicable Delaware law, we are only permitted to make distributions either out of "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock), or out of net profits for the fiscal year in which the distribution is declared or the prior fiscal year.
Under the terms of the Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock, unless full cumulative dividends have been or contemporaneously are being paid or declared and a sum sufficient for the payment thereof set apart for payment on all outstanding Series A Preferred Stock (and any parity securities), Series B Preferred Stock (and any parity securities), and Series C Preferred Stock (and any parity securities), respectively, with respect to dividends through the most recent dividend payment dates, (i) no dividend may be declared or paid or set apart for payment on any junior security (other than a dividend payable solely in junior securities with respect to both dividends and the liquidation, winding-up and dissolution of our affairs), including our common stock, and (ii) we may not redeem, purchase or otherwise acquire any parity security or junior security, including our common stock, in each case subject to certain exceptions as described in the certificate of designation of the Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock, respectively.
16. SEGMENT INFORMATION
The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) 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.
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 production and fuel logistics management. The Texas segment represents results from Vistra's electricity generation operations in the ERCOT market, other than assets that are now part of the Sunset or Asset Closure segments. The East segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets that are now part of the Sunset or Asset Closure segments, and includes operations in the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results from these markets into one reportable segment, East, given similar economic characteristics. The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site.
The Sunset segment consists of generation plants with announced retirement dates after December 31, 2024. Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments. We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement dates after December 31, 2024.
The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 3). Upon movement of generation plant assets to either the Sunset or Asset Closure segments, prior year results are retrospectively adjusted, if the effects are material, for comparative purposes. Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines.
Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services 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 of our 2023 Form 10-K, as well as those disclosed in Note 1 of this quarterly report on Form 10-Q. 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. 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.
| Three Months Ended | Retail | Texas | East | West | Sunset | Asset Closure | Corporate and Other (a) | Eliminations | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | 4,251 | $ | 4,104 | $ | 1,524 | $ | 242 | $ | 469 | $ | 1 | $ | — | $ | (4,303) | $ | 6,288 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | 3,383 | 1,517 | 651 | 344 | 224 | — | 1 | (2,034) | 4,086 | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | (31) | $ | (153) | $ | (223) | $ | (22) | $ | (20) | $ | — | $ | (17) | $ | — | $ | (466) | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | (26) | (132) | (161) | (22) | (16) | — | (18) | — | (375) | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | (1,210) | $ | 3,215 | $ | 362 | $ | 151 | $ | 168 | $ | (24) | $ | (74) | $ | — | $ | 2,588 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | 247 | 429 | 29 | 256 | (42) | (23) | (62) | — | 834 | |||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | (1,226) | $ | 3,249 | $ | 468 | $ | 153 | $ | 163 | $ | (18) | $ | (952) | $ | — | $ | 1,837 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | 245 | 438 | 29 | 264 | (44) | (17) | (413) | — | 502 | |||||||||||||||||||||||||||||||||||||||||||||||
| Nine Months Ended | Retail | Texas | East | West | Sunset | Asset Closure | Corporate and Other (a) | Eliminations | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | 9,913 | $ | 4,716 | $ | 3,354 | $ | 729 | $ | 1,095 | $ | 1 | $ | 1 | $ | (6,622) | $ | 13,187 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | 8,161 | 3,061 | 3,305 | 799 | 1,366 | — | 1 | (4,992) | 11,701 | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | (85) | $ | (418) | $ | (631) | $ | (64) | $ | (58) | $ | — | $ | (50) | $ | — | $ | (1,306) | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | (78) | (390) | (488) | (56) | (45) | — | (52) | — | (1,109) | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | 271 | $ | 2,265 | $ | 507 | $ | 427 | $ | 301 | $ | (73) | $ | (216) | $ | — | $ | 3,482 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | 481 | 350 | 1,048 | 456 | 447 | (78) | (145) | — | 2,559 | |||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | 232 | $ | 2,327 | $ | 693 | $ | 430 | $ | 296 | $ | (64) | $ | (1,592) | $ | — | $ | 2,322 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | 462 | 396 | 1,049 | 481 | 442 | 23 | (1,177) | — | 1,676 | |||||||||||||||||||||||||||||||||||||||||||||||
| Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2024 | $ | 3 | $ | 583 | $ | 203 | $ | 15 | $ | 21 | $ | — | $ | 39 | $ | — | $ | 864 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2023 | 1 | 366 | 77 | 10 | 61 | — | 44 | — | 559 |
(a)Income tax (expense) benefit is generally not reflected in net income (loss) of the segments but is reflected almost entirely in Corporate and Other net income (loss).
17. SUPPLEMENTARY FINANCIAL INFORMATION
Impairment of Long-Lived Assets
In the first quarter of 2023, we recognized an impairment loss of $49 million related to our Kincaid generation facility in Illinois as a result of a significant decrease in the projected operating margins of the facility, primarily driven by a decrease in projected power prices. The impairment is reported in our Sunset segment and includes write-downs of property, plant and equipment of $45 million, write-downs of inventory of $2 million and write-downs of operating lease right-of-use assets of $2 million.
In determining the fair value of the impaired asset group, we utilized the income approach described in ASC 820, Fair Value Measurement.
Interest Expense and Related Charges
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Interest expense | $ | 244 | $ | 161 | $ | 702 | $ | 474 | |||||||||||||||
| Unrealized mark-to-market net (gains) losses on interest rate swaps | 84 | (43) | 26 | (65) | |||||||||||||||||||
| Amortization of debt issuance costs, discounts and premiums | 9 | 7 | 25 | 19 | |||||||||||||||||||
| Facility Fee expense | 3 | — | 11 | — | |||||||||||||||||||
| Debt extinguishment gain | — | — | (6) | — | |||||||||||||||||||
| Capitalized interest | (20) | (7) | (52) | (28) | |||||||||||||||||||
| Other | 12 | 25 | 37 | 50 | |||||||||||||||||||
| Total interest expense and related charges | $ | 332 | $ | 143 | $ | 743 | $ | 450 |
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 5.52% and 5.57% as of September 30, 2024 and 2023, respectively.
Other Income and Deductions
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2024 | 2023 | 2024 | 2023 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Other income: | |||||||||||||||||||||||
| NDT net income (a) | $ | 95 | $ | — | $ | 170 | $ | — | |||||||||||||||
| Insurance settlements (b) | 21 | 12 | 22 | 21 | |||||||||||||||||||
| Gain on sale of land (c) | 5 | 1 | 6 | 95 | |||||||||||||||||||
| Gain on TRA repurchases (d) | — | — | 10 | — | |||||||||||||||||||
| Interest income | 9 | 16 | 50 | 42 | |||||||||||||||||||
| All other | 9 | 3 | 34 | 16 | |||||||||||||||||||
| Total other income | $ | 139 | $ | 32 | $ | 292 | $ | 174 | |||||||||||||||
| Other deductions: | |||||||||||||||||||||||
| All other | 3 | 3 | $ | 10 | $ | 9 | |||||||||||||||||
| Total other deductions | $ | 3 | $ | 3 | $ | 10 | $ | 9 |
(a)Includes interest, dividends, and net realized and unrealized gains and losses associated with the NDTs of the PJM nuclear facilities. Reported in the East segment.
(b)For three and nine months ended September 30, 2024, $20 million reported in the Texas segment, and $1 million and $2 million reported in the West segment, respectively. For the three and nine months ended September 30, 2023, $8 million and $17 million, respectively, reported in the West segment and $4 million and $4 million, respectively, reported in the Asset Closure segment.
(c)For the three and nine months ended September 30, 2024 and the three months ended September 30, 2023, amounts reported in the Asset Closure segment. For the nine months ended September 30, 2023, $94 million reported in the Asset Closure segment and $1 million reported in the Texas segment.
(d)Reported in Corporate and Other.
Restricted Cash
| September 30, 2024 | December 31, 2023 | ||||||||||||||||||||||
| Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Amounts related to remediation escrow accounts | $ | 29 | $ | 6 | $ | 40 | $ | 14 | |||||||||||||||
| Total restricted cash | $ | 29 | $ | 6 | $ | 40 | $ | 14 |
Inventories by Major Category
| September 30, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Materials and supplies | $ | 534 | $ | 289 | |||||||
| Fuel stock | 383 | 420 | |||||||||
| Natural gas in storage | 32 | 31 | |||||||||
| Total inventories | $ | 949 | $ | 740 |
Investments
| September 30, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Nuclear decommissioning trusts (Note 13) | $ | 4,444 | $ | 1,951 | |||||||
| Assets related to employee benefit plans | 18 | 28 | |||||||||
| Land investments | 42 | 42 | |||||||||
| Other investments | 16 | 14 | |||||||||
| Total investments | $ | 4,520 | $ | 2,035 |
Property, Plant and Equipment
| September 30, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Power generation and structures | $ | 22,527 | $ | 17,297 | |||||||
| Land | 603 | 572 | |||||||||
| Office and other equipment | 163 | 159 | |||||||||
| Total | 23,293 | 18,028 | |||||||||
| Less accumulated depreciation | (7,583) | (6,657) | |||||||||
| Net of accumulated depreciation | 15,710 | 11,371 | |||||||||
| Finance lease right-of-use assets (net of accumulated depreciation) | 155 | 160 | |||||||||
| Nuclear fuel (net of accumulated amortization of $389 million and $120 million) | 1,398 | 379 | |||||||||
| Construction work in progress | 1,125 | 522 | |||||||||
| Property, plant and equipment — net | $ | 18,388 | $ | 12,432 |
Depreciation expenses totaled $421 million and $335 million for the three months ended September 30, 2024 and 2023, respectively, and $1.179 billion and $989 million for nine months ended September 30, 2024 and 2023, respectively.
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
| September 30, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Retirement and other employee benefits | $ | 239 | $ | 247 | |||||||
| Winter Storm Uri impact (a) | 1 | 26 | |||||||||
| Identifiable intangible liabilities (Note 7) | 163 | 131 | |||||||||
| Regulatory liability (b) | 470 | 209 | |||||||||
| Finance lease liabilities | 220 | 227 | |||||||||
| Liability for third-party remediation | 8 | 17 | |||||||||
| Accrued severance costs | 35 | 36 | |||||||||
| Other accrued expenses | 55 | 58 | |||||||||
| Total other noncurrent liabilities and deferred credits | $ | 1,191 | $ | 951 |
(a)Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.
(b)As of September 30, 2024 and December 31, 2023, 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 $470 million and $209 million, respectively, in other noncurrent liabilities and deferred credits.
Fair Value of Debt
| September 30, 2024 | December 31, 2023 | |||||||||||||||||||||||||||||||
| Long-term debt (see Note 9): | Fair Value Hierarchy | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||
| Long-term debt under the Vistra Operations Credit Facilities | Level 2 | $ | 2,441 | $ | 2,478 | $ | 2,456 | $ | 2,500 | |||||||||||||||||||||||
| Vistra Zero Term Loan B Facility | Level 2 | 685 | 696 | — | — | |||||||||||||||||||||||||||
| Vistra Operations Senior Notes | Level 2 | 11,124 | 11,429 | 11,881 | 11,752 | |||||||||||||||||||||||||||
| Energy Harbor Revenue Bonds | Level 2 | 414 | 446 | — | — | |||||||||||||||||||||||||||
| Equipment Financing Agreements | Level 3 | 66 | 66 | 65 | 62 | |||||||||||||||||||||||||||
We determine fair value in accordance with accounting standards as discussed in Note 11. 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.
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 as of September 30, 2024 and December 31, 2023:
| September 30, 2024 | December 31, 2023 | ||||||||||
| (in millions) | |||||||||||
| Cash and cash equivalents | $ | 905 | $ | 3,485 | |||||||
| Restricted cash included in current assets | 29 | 40 | |||||||||
| Restricted cash included in noncurrent assets | 6 | 14 | |||||||||
| Total cash, cash equivalents and restricted cash | $ | 940 | $ | 3,539 |
The following table summarizes our supplemental cash flow information for the nine months ended September 30, 2024 and 2023. See Note 2 for other non-cash investing and financing activity related to the Energy Harbor Merger.
| Nine Months Ended September 30, | |||||||||||
| 2024 | 2023 | ||||||||||
| (in millions) | |||||||||||
| Cash payments related to: | |||||||||||
| Interest paid | $ | 709 | $ | 527 | |||||||
| Capitalized interest | (52) | (28) | |||||||||
| Interest paid (net of capitalized interest) | $ | 657 | $ | 499 | |||||||
For the nine months ended September 30, 2024 and 2023, we paid federal income tax of $2 million and zero, respectively, paid state income taxes of $52 million and $31 million respectively, and received state tax refunds of $8 million and $12 million, respectively.
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