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 Per Share Amounts)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Operating revenues (Note 4) | $ | 5,146 | $ | 2,991 | $ | 9,859 | $ | 8,763 | |||||||||||||||
| Fuel, purchased power costs and delivery fees | (3,139) | (1,763) | (7,580) | (7,827) | |||||||||||||||||||
| Operating costs | (400) | (372) | (1,250) | (1,173) | |||||||||||||||||||
| Depreciation and amortization | (390) | (468) | (1,214) | (1,355) | |||||||||||||||||||
| Selling, general and administrative expenses | (323) | (269) | (894) | (771) | |||||||||||||||||||
| Impairment of long-lived assets (Note 17) | — | — | — | (38) | |||||||||||||||||||
| Operating income (loss) | 894 | 119 | (1,079) | (2,401) | |||||||||||||||||||
| Other income (Note 17) | 10 | 16 | 88 | 108 | |||||||||||||||||||
| Other deductions (Note 17) | (5) | (5) | (18) | (13) | |||||||||||||||||||
| Interest expense and related charges (Note 17) | (71) | (124) | (186) | (288) | |||||||||||||||||||
| Impacts of Tax Receivable Agreement (Note 7) | 86 | 35 | (29) | 31 | |||||||||||||||||||
| Net income (loss) before income taxes | 914 | 41 | (1,224) | (2,563) | |||||||||||||||||||
| Income tax (expense) benefit (Note 6) | (236) | (31) | 262 | 569 | |||||||||||||||||||
| Net income (loss) | $ | 678 | $ | 10 | $ | (962) | $ | (1,994) | |||||||||||||||
| Net income attributable to noncontrolling interest | (10) | (3) | (19) | (6) | |||||||||||||||||||
| Net income (loss) attributable to Vistra | $ | 668 | $ | 7 | $ | (981) | $ | (2,000) | |||||||||||||||
| Cumulative dividends attributable to preferred stock | (37) | — | (112) | — | |||||||||||||||||||
| Net income (loss) attributable to Vistra common stock | $ | 631 | $ | 7 | $ | (1,093) | $ | (2,000) | |||||||||||||||
| Weighted average shares of common stock outstanding: | |||||||||||||||||||||||
| Basic | 413,762,896 | 482,516,965 | 431,381,151 | 483,150,213 | |||||||||||||||||||
| Diluted | 417,482,511 | 484,494,546 | 431,381,151 | 483,150,213 | |||||||||||||||||||
| Net income (loss) per weighted average share of common stock outstanding: | |||||||||||||||||||||||
| Basic | $ | 1.53 | $ | 0.01 | $ | (2.53) | $ | (4.14) | |||||||||||||||
| Diluted | $ | 1.51 | $ | 0.01 | $ | (2.53) | $ | (4.14) |
See Notes to the Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited) (Millions of Dollars)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Net income (loss) | $ | 678 | $ | 10 | $ | (962) | $ | (1,994) | |||||||||||||||
| Other comprehensive income, net of tax effects: | |||||||||||||||||||||||
| Effects related to pension and other retirement benefit obligations (net of tax expense of $2, $4, $2 and $5) | 6 | 14 | 6 | 17 | |||||||||||||||||||
| Total other comprehensive income | 6 | 14 | 6 | 17 | |||||||||||||||||||
| Comprehensive income (loss) | $ | 684 | $ | 24 | $ | (956) | $ | (1,977) | |||||||||||||||
| Comprehensive income attributable to noncontrolling interest | (10) | (3) | (19) | (6) | |||||||||||||||||||
| Comprehensive income (loss) attributable to Vistra | $ | 674 | $ | 21 | $ | (975) | $ | (1,983) |
See Notes to the Condensed Consolidated Financial Statements.
| VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars) | |||||||||||
| Nine Months Ended September 30, | |||||||||||
| 2022 | 2021 | ||||||||||
| Cash flows — operating activities: | |||||||||||
| Net loss | $ | (962) | $ | (1,994) | |||||||
| Adjustments to reconcile net loss to cash provided by (used in) operating activities: | |||||||||||
| Depreciation and amortization | 1,575 | 1,551 | |||||||||
| Deferred income tax benefit, net | (298) | (587) | |||||||||
| Impairment of long-lived assets | — | 38 | |||||||||
| Unrealized net loss from mark-to-market valuations of commodities | 2,027 | 771 | |||||||||
| Unrealized net gain from mark-to-market valuations of interest rate swaps | (261) | (92) | |||||||||
| Asset retirement obligation accretion expense | 26 | 27 | |||||||||
| Impacts of Tax Receivable Agreement | 29 | (31) | |||||||||
| Stock-based compensation | 48 | 36 | |||||||||
| Bad debt expense | 136 | 86 | |||||||||
| Other, net | — | (7) | |||||||||
| Changes in operating assets and liabilities: | |||||||||||
| Margin deposits, net | (1,805) | (767) | |||||||||
| Uplift securitization proceeds receivable from ERCOT | 544 | — | |||||||||
| Accrued interest | (31) | (55) | |||||||||
| Accrued taxes | (46) | (63) | |||||||||
| Accrued employee incentive | (17) | (86) | |||||||||
| Other operating assets and liabilities | (873) | 680 | |||||||||
| Cash provided by (used in) operating activities | 92 | (493) | |||||||||
| Cash flows — investing activities: | |||||||||||
| Capital expenditures, including nuclear fuel purchases and LTSA prepayments | (909) | (790) | |||||||||
| Proceeds from sales of nuclear decommissioning trust fund securities | 428 | 366 | |||||||||
| Investments in nuclear decommissioning trust fund securities | (446) | (382) | |||||||||
| Proceeds from sales of environmental allowances | 358 | 102 | |||||||||
| Purchases of environmental allowances | (343) | (247) | |||||||||
| Insurance proceeds | 15 | 74 | |||||||||
| Proceeds from sale of assets | 21 | 7 | |||||||||
| Other, net | (10) | 27 | |||||||||
| Cash used in investing activities | (886) | (843) | |||||||||
| Cash flows — financing activities: | |||||||||||
| Issuances of long-term debt | 1,498 | 1,250 | |||||||||
| Borrowings under Commodity-Linked Facility | 2,750 | — | |||||||||
| Repayments under Commodity-Linked Facility | (2,750) | — | |||||||||
| Borrowings under Term Loan A | — | 1,250 | |||||||||
| Repayment under Term Loan A | — | (1,250) | |||||||||
| Proceeds from forward capacity agreement | — | 500 | |||||||||
| Repayments/repurchases of debt | (232) | (234) | |||||||||
| Net borrowings under accounts receivable financing | 625 | 175 | |||||||||
| Borrowings under Revolving Credit Facility | 1,500 | 1,300 | |||||||||
| Repayments under Revolving Credit Facility | (1,500) | (1,300) | |||||||||
| Share repurchases | (1,590) | (175) | |||||||||
| Dividends paid to common stockholders | (227) | (219) |
| VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars) | |||||||||||
| Nine Months Ended September 30, | |||||||||||
| 2022 | 2021 | ||||||||||
| Dividends paid to preferred stockholders | (76) | — | |||||||||
| Debt tender offer and other financing fees | (29) | (13) | |||||||||
| Other, net | 34 | (5) | |||||||||
| Cash provided by financing activities | 3 | 1,279 | |||||||||
| Net change in cash, cash equivalents and restricted cash | (791) | (57) | |||||||||
| Cash, cash equivalents and restricted cash — beginning balance | 1,359 | 444 | |||||||||
| Cash, cash equivalents and restricted cash — ending balance | $ | 568 | $ | 387 |
See Notes to the Condensed Consolidated Financial Statements.
| VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars) | |||||||||||
| September 30, 2022 | December 31, 2021 | ||||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 535 | $ | 1,325 | |||||||
| Restricted cash (Note 17) | 23 | 21 | |||||||||
| Trade accounts receivable — net (Note 17) | 1,854 | 1,397 | |||||||||
| Income taxes receivable | — | 15 | |||||||||
| Inventories (Note 17) | 590 | 610 | |||||||||
| Commodity and other derivative contractual assets (Note 14) | 6,786 | 2,513 | |||||||||
| Margin deposits related to commodity contracts | 3,066 | 1,263 | |||||||||
| Uplift securitization proceeds receivable from ERCOT (Note 1) | — | 544 | |||||||||
| Prepaid expense and other current assets | 291 | 195 | |||||||||
| Total current assets | 13,145 | 7,883 | |||||||||
| Restricted cash (Note 17) | 10 | 13 | |||||||||
| Investments (Note 17) | 1,637 | 2,049 | |||||||||
| Property, plant and equipment — net (Note 17) | 12,550 | 13,056 | |||||||||
| Operating lease right-of-use assets | 39 | 40 | |||||||||
| Goodwill (Note 5) | 2,583 | 2,583 | |||||||||
| Identifiable intangible assets — net (Note 5) | 2,002 | 2,146 | |||||||||
| Commodity and other derivative contractual assets (Note 14) | 1,062 | 250 | |||||||||
| Accumulated deferred income taxes | 1,653 | 1,302 | |||||||||
| Other noncurrent assets | 494 | 361 | |||||||||
| Total assets | $ | 35,175 | $ | 29,683 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
| Accounts receivable financing (Note 9) | $ | 625 | $ | — | |||||||
| Long-term debt due currently (Note 10) | 38 | 254 | |||||||||
| Trade accounts payable | 1,398 | 1,515 | |||||||||
| Commodity and other derivative contractual liabilities (Note 14) | 8,796 | 3,023 | |||||||||
| Margin deposits related to commodity contracts | 37 | 39 | |||||||||
| Accrued income taxes | 6 | — | |||||||||
| Accrued taxes other than income | 154 | 207 | |||||||||
| Accrued interest | 112 | 143 | |||||||||
| Asset retirement obligations (Note 17) | 121 | 104 | |||||||||
| Operating lease liabilities | 8 | 5 | |||||||||
| Other current liabilities | 616 | 553 | |||||||||
| Total current liabilities | 11,911 | 5,843 | |||||||||
| Long-term debt, less amounts due currently (Note 10) | 11,947 | 10,477 | |||||||||
| Operating lease liabilities | 33 | 38 | |||||||||
| Commodity and other derivative contractual liabilities (Note 14) | 1,803 | 804 | |||||||||
| Tax Receivable Agreement obligation (Note 7) | 423 | 394 | |||||||||
| Asset retirement obligations (Note 17) | 2,340 | 2,346 | |||||||||
| Other noncurrent liabilities and deferred credits (Note 17) | 1,117 | 1,489 | |||||||||
| Total liabilities | 29,574 | 21,391 |
| VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars) | |||||||||||
| September 30, 2022 | December 31, 2021 | ||||||||||
| Commitments and Contingencies (Note 11) | |||||||||||
| Total equity (Note 12): | |||||||||||
| Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation preference — $1,000; shares outstanding: September 30, 2022 and December 31, 2021— 1,000,000); Series B (liquidation preference — $1,000; shares outstanding: September 30, 2022 and December 31, 2021 — 1,000,000) | 2,000 | 2,000 | |||||||||
| Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: September 30, 2022 — 405,444,072; December 31, 2021 — 469,072,597) | 5 | 5 | |||||||||
| Treasury stock, at cost (shares: September 30, 2022 — 131,640,516; December 31, 2021 — 63,856,879) | (3,052) | (1,558) | |||||||||
| Additional paid-in-capital | 9,923 | 9,824 | |||||||||
| Retained deficit | (3,284) | (1,964) | |||||||||
| Accumulated other comprehensive loss | (10) | (16) | |||||||||
| Stockholders' equity | 5,582 | 8,291 | |||||||||
| Noncontrolling interest in subsidiary | 19 | 1 | |||||||||
| Total equity | 5,601 | 8,292 | |||||||||
| Total liabilities and equity | $ | 35,175 | $ | 29,683 |
See Notes to the Condensed Consolidated Financial Statements.
VISTRA CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
**1.**BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Description of Business
References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary 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.
Winter Storm Uri
In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Winter Storm Uri had a material adverse impact on our 2021 results of operations and operating cash flows.
Uplift Securitization Proceeds from ERCOT — As part of the 2021 regular Texas legislative sessions and in response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, the Texas legislature passed House Bill (HB) 4492 for ERCOT to obtain financing to distribute to load-serving entities (LSEs) that were uplifted and paid to ERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri. In October 2021, the PUCT issued a Debt Obligation Order approving $2.1 billion financing and the methodology for allocation of proceeds to the LSEs. In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we received $544 million of proceeds from ERCOT in the second quarter of 2022. The Company accounted for the proceeds we received by analogy to the contribution model within Accounting Standards Codification (ASC) 958-605, Not-for-Profit Entities - Revenue Recognition and the grant model within International Accounting Standard 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to expenses in the statements of operations in the annual period for which the proceeds are intended to compensate. We concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received were determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $2.1 billion funding approved in the Debt Obligation Order. The final financial impact of Winter Storm Uri continues to be subject to the outcome of litigation arising from the event.
Recent Developments
Dividends Declared — In October 2022, the Board declared a quarterly dividend of $0.193 per share of common stock that will be paid in December 2022. In October 2022, the Board declared a semi-annual dividend of $35.00 per share of Series B Preferred Stock that will be paid in December 2022.
Commodity-Linked Revolving Credit Facility — On October 5, 2022, Vistra initiated an amendment to the Commodity-Linked Facility to, among other things, (i) extend the maturity date to October 2023 and (ii) reduce the aggregate available commitments to $1.25 billion. On October 21, 2022, the Commodity-Linked Facility was further amended to increase the aggregate available commitments to $1.35 billion.
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 2021 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. 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 2021 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.
In the third quarter of 2021, the Company determined that depreciation expense on certain property, plant, and equipment assets was calculated incorrectly in prior years as a result of incorrectly assigned useful lives to these assets, which resulted in a misstatement to depreciation expense and accumulated depreciation. Additionally, an error was identified related to assets that were incorrectly retired prior to the end of their useful lives. The Company identified that depreciation expense and accumulated depreciation was understated by $23 million, $39 million and $3 million for the years ended December 31, 2018, 2019, and 2020, respectively, and overstated by $20 million for the six-month period ended June 30, 2021. In order to correct for the misstatements, the Company recorded an out-of-period adjustment to depreciation expense of $45 million for the three months ended September 30, 2021. The Company evaluated the effects of this out-of-period adjustment, both qualitatively and quantitatively, and concluded that this adjustment was not material to the Company's financial position or results of operations for the third quarter of 2021 or any prior periods.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at 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.
2. DEVELOPMENT OF GENERATION FACILITIES
Texas Segment Solar Generation and Energy Storage Projects
We have announced the planned development of up to 768 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. The first 158 MW of solar generation came online in January and February 2022 and the battery ESS came online in April 2022. Estimated commercial operation dates for the remaining facilities range from summer of 2024 to the end of 2026. At September 30, 2022, we had accumulated approximately $40 million in construction-work-in-process for these remaining Texas segment solar generation projects.
East Segment Solar Generation and Energy Storage Projects
In September 2021, we announced the planned development of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act. Estimated commercial operation dates for these facilities range from 2024 to 2025.
West Segment Energy Storage Projects
Oakland — In June 2019, East Bay Community Energy (EBCE) signed a ten-year contract to receive resource adequacy capacity from the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California. In April 2020, the project received necessary approvals from EBCE and from Pacific Gas and Electric Company (PG&E). The contract was amended to increase the capacity of the planned development to a 36.25 MW battery ESS. In April 2020, the concurrent Local Area Reliability Service (LARS) agreement to ensure grid reliability as part of the Oakland Clean Energy Initiative was signed, but required California Public Utilities Commission (CPUC) approval. PG&E did not receive CPUC approval as of April 15, 2021. On April 16, 2021, Vistra terminated the LARS agreement with PG&E. We are continuing development of the Oakland battery ESS project while seeking another contractual arrangement that will allow the investment to move forward.
Moss Landing — In June 2018, we announced that, subject to approval by the CPUC, we would enter into a 20-year resource adequacy contract with PG&E to develop a 300 MW battery ESS at our Moss Landing Power Plant site in California (Moss Landing Phase I). The CPUC approved the resource adequacy contract in November 2018. Under the contract, PG&E will pay us a fixed monthly resource adequacy payment, while we will receive the energy revenues and incur the costs from dispatching and charging the ESS. Moss Landing Phase I commenced commercial operations in May 2021.
In May 2020, we announced that, subject to approval by the CPUC, we would enter into a 10-year resource adequacy contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase II). The CPUC approved the resource adequacy contract in August 2020. Moss Landing Phase II commenced commercial operations in July 2021.
In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15-year resource adequacy and energy settlement contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III). The CPUC approved the resource adequacy and energy settlement contract in April 2022. Moss Landing Phase III is expected to enter commercial operations in the summer of 2023. At September 30, 2022, we had accumulated approximately $63 million in construction-work-in-process for Moss Landing Phase III.
Moss Landing Outages — In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS. A review found the root cause originated in systems separate from the battery system. The facility was offline as we performed the work necessary to return the facility to service. Restoration work on the facility was completed in June 2022. Moss Landing Phases II and III were not affected by this incident.
In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the battery ESS. A review found the root cause originated in systems separate from the battery system. The facility was offline as we performed the work necessary to return the facility to service. Restoration work on the facility was completed in September 2022. Moss Landing Phases I and III were not affected by this incident.
These incidents did not have a material impact on our results of operations.
3. RETIREMENT OF GENERATION FACILITIES
In 2020, we announced our intention to retire all of our remaining coal generation facilities in Illinois and Ohio, one coal generation facility in Texas and one natural gas facility in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 11), and in furtherance of our efforts to significantly reduce our carbon footprint. As previously announced in April 2021, we retired the Joppa generation facilities in September 2022 in order to settle a complaint filed with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018. As previously announced in July 2021, we retired the Zimmer coal generation facility in June 2022 due to the inability to secure capacity revenues for the plant in the PJM capacity auction held in May 2021.
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 move 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) | Actual or Expected 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 | Sunset | ||||||||||||||||||||||||||||||||
| Edwards | Bartonville, IL | MISO | Coal | 585 | January 1, 2023 | Sunset | ||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||||||||
| Zimmer | Moscow, OH | PJM | Coal | 1,300 | Retired June 1, 2022 | Asset Closure | ||||||||||||||||||||||||||||||||
| Total | 7,486 |
(a)Generation facilities may retire earlier than the end of 2027 if economic or other conditions dictate.
4. REVENUE
| Three Months Ended September 30, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Sunset | Asset Closure | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers: | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail energy charge in ERCOT | $ | 2,186 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 2,186 | |||||||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest | 491 | — | — | — | — | — | — | 491 | |||||||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 669 | 329 | 157 | 385 | 74 | — | 1,614 | |||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (a) | — | — | 14 | — | — | — | — | 14 | |||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 127 | 328 | 40 | 38 | — | — | 533 | |||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 2,677 | 796 | 671 | 197 | 423 | 74 | — | 4,838 | |||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||
| Intangible amortization | 2 | — | — | — | (1) | — | — | 1 | |||||||||||||||||||||||||||||||||||||||
| Hedging and other revenues (b) | 579 | 176 | (83) | 36 | (396) | (6) | 1 | 307 | |||||||||||||||||||||||||||||||||||||||
| Affiliate sales (c) | — | 2,655 | 538 | 3 | 254 | — | (3,450) | — | |||||||||||||||||||||||||||||||||||||||
| Total other revenues | 581 | 2,831 | 455 | 39 | (143) | (6) | (3,449) | 308 | |||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 3,258 | $ | 3,627 | $ | 1,126 | $ | 236 | $ | 280 | $ | 68 | $ | (3,449) | $ | 5,146 |
(a)Represents net capacity sold in each ISO/RTO. The East segment includes $37 million of capacity sold offset by $23 million of capacity purchased.
(b)Includes $346 million of unrealized net gains from mark-to-market valuations of commodity positions, including Retail segment unrealized net gains of $217 million due to the discontinuance of normal purchases or normal sales (NPNS) accounting on retail electric contract portfolios in the third quarter of 2021 and second quarter of 2022 where physical settlement is no longer considered probable throughout the contract term. See Note 16 for unrealized net gains (losses) by segment.
(c)Texas, East and Sunset segments include $1.213 billion, $80 million and $134 million, respectively, of affiliated unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.
| Three Months Ended September 30, 2021 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Sunset | Asset Closure | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers: | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail energy charge in ERCOT | $ | 1,896 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1,896 | |||||||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest | 624 | — | — | — | — | — | — | 624 | |||||||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 211 | 191 | 89 | 198 | 124 | — | 813 | |||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (a) | — | — | (13) | 1 | 39 | 12 | — | 39 | |||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 88 | 167 | 29 | 45 | 1 | — | 330 | |||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 2,520 | 299 | 345 | 119 | 282 | 137 | — | 3,702 | |||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||
| Intangible amortization | 2 | — | — | — | (2) | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Hedging and other revenues (b) | (362) | (7) | 222 | (30) | (337) | (197) | — | (711) | |||||||||||||||||||||||||||||||||||||||
| Affiliate sales (c) | — | 551 | (59) | 1 | (5) | — | (488) | — | |||||||||||||||||||||||||||||||||||||||
| Total other revenues | (360) | 544 | 163 | (29) | (344) | (197) | (488) | (711) | |||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 2,160 | $ | 843 | $ | 508 | $ | 90 | $ | (62) | $ | (60) | $ | (488) | $ | 2,991 |
(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $116 million of capacity purchased offset by $103 million of capacity sold. The West segment includes $1 million of capacity sold. The Sunset segment includes $40 million of capacity sold offset by $1 million of capacity purchased. The Asset Closure segment includes $12 million of capacity sold.
(b)Includes $861 million of unrealized net losses from mark-to-market valuations of commodity positions, including Retail segment unrealized net losses of $357 million due to the discontinuance of NPNS accounting on a retail electric contract portfolio in the third quarter of 2021 where physical settlement is no longer considered probable throughout the contract term. See Note 16 for unrealized net gains (losses) by segment.
(c)Texas, East and Sunset segments include $527 million, $472 million and $118 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.
| Nine Months Ended September 30, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Sunset | Asset Closure | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers: | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail energy charge in ERCOT | $ | 5,349 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 5,349 | |||||||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest | 1,673 | — | — | — | — | — | — | 1,673 | |||||||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 761 | 901 | 268 | 775 | 392 | — | 3,097 | |||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (a) | — | — | 4 | — | 63 | 20 | — | 87 | |||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 392 | 773 | 114 | 118 | 22 | — | 1,419 | |||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 7,022 | 1,153 | 1,678 | 382 | 956 | 434 | — | 11,625 | |||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||
| Intangible amortization | 1 | — | 1 | — | (6) | — | — | (4) | |||||||||||||||||||||||||||||||||||||||
| Hedging and other revenues (b) | (147) | (275) | (70) | (4) | (1,129) | (138) | 1 | (1,762) | |||||||||||||||||||||||||||||||||||||||
| Affiliate sales (c) | — | 1,031 | 791 | 9 | 235 | — | (2,066) | — | |||||||||||||||||||||||||||||||||||||||
| Total other revenues | (146) | 756 | 722 | 5 | (900) | (138) | (2,065) | (1,766) | |||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 6,876 | $ | 1,909 | $ | 2,400 | $ | 387 | $ | 56 | $ | 296 | $ | (2,065) | $ | 9,859 |
(a)Represents net capacity sold in each ISO/RTO. The East segment includes $265 million of capacity sold offset by $261 million of capacity purchased. The Sunset segment includes $66 million of capacity sold offset by $3 million of capacity purchased. The Asset Closure segment includes $20 million of capacity sold.
(b)Includes $2.101 billion of unrealized net losses from mark-to-market valuations of commodity positions, including Retail segment unrealized net losses of $780 million due to the discontinuance of NPNS accounting on retail electric contract portfolios in the third quarter of 2021 and second quarter of 2022 where physical settlement is no longer considered probable throughout the contract term. See Note 16 for unrealized net gains (losses) by segment.
(c)Texas, East and Sunset segments include $1.715 billion, $580 million and $118 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.
| Nine Months Ended September 30, 2021 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Sunset | Asset Closure | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Retail energy charge in ERCOT | $ | 4,460 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 4,460 | |||||||||||||||||||||||||||||||||||||
| Retail energy charge in Northeast/Midwest | 1,715 | — | — | — | — | — | — | 1,715 | |||||||||||||||||||||||||||||||||||||||||||||
| Wholesale generation revenue from ISO/RTO | — | 3,585 | 442 | 158 | 1,006 | 224 | — | 5,415 | |||||||||||||||||||||||||||||||||||||||||||||
| Capacity revenue from ISO/RTO (a) | — | — | (14) | 1 | 99 | 34 | — | 120 | |||||||||||||||||||||||||||||||||||||||||||||
| Revenue from other wholesale contracts | — | 2,172 | 459 | 75 | 147 | 1 | — | 2,854 | |||||||||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 6,175 | 5,757 | 887 | 234 | 1,252 | 259 | — | 14,564 | |||||||||||||||||||||||||||||||||||||||||||||
| Other revenues: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Intangible amortization | (1) | — | 74 | — | (10) | — | — | 63 | |||||||||||||||||||||||||||||||||||||||||||||
| Hedging and other revenues (b) | (345) | (4,457) | 418 | (66) | (1,075) | (339) | — | (5,864) | |||||||||||||||||||||||||||||||||||||||||||||
| Affiliate sales (c) | — | 158 | 359 | 3 | 21 | 1 | (542) | — | |||||||||||||||||||||||||||||||||||||||||||||
| Total other revenues | (346) | (4,299) | 851 | (63) | (1,064) | (338) | (542) | (5,801) | |||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 5,829 | $ | 1,458 | $ | 1,738 | $ | 171 | $ | 188 | $ | (79) | $ | (542) | $ | 8,763 |
(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $346 million of capacity purchased offset by $332 million of capacity sold. The West segment includes $1 million of capacity sold. The Sunset segment includes $101 million of capacity sold offset by $2 million of capacity purchased. The Asset Closure segment includes $34 million of capacity sold.
(b)Includes $1.146 billion of unrealized net losses from mark-to-market valuations of commodity positions, including Retail segment unrealized net losses of $357 million due to the discontinuance of NPNS accounting on a retail electric contract portfolio in the third quarter of 2021 where physical settlement is no longer considered probable throughout the contract term. See Note 16 for unrealized net gains (losses) by segment.
(c)Texas, East and Sunset segments include $2.153 billion, $819 million and $272 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.
Performance Obligations
As of September 30, 2022, we have future 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. Therefore, an obligation exists as of the date of the results of the respective ISO/RTO capacity auction or the contract execution date. These obligations total $90 million, $483 million, $311 million, $222 million and $111 million that will be recognized, in the balance of the year ended December 31, 2022 and the years ending December 31, 2023, 2024, 2025 and 2026, respectively, and $735 million thereafter. Capacity revenues are recognized as capacity is made available to the related ISOs/RTOs or counterparties.
Accounts Receivable
The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both contracts with customers and other activities:
| September 30, 2022 | December 31, 2021 | ||||||||||
| Trade accounts receivable from contracts with customers — net | $ | 1,411 | $ | 1,087 | |||||||
| Other trade accounts receivable — net | 443 | 310 | |||||||||
| Total trade accounts receivable — net | $ | 1,854 | $ | 1,397 |
5. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
Goodwill
As of both September 30, 2022 and December 31, 2021, the carrying value of goodwill totaled $2.583 billion, including $2.461 billion allocated to our Retail reporting unit and $122 million allocated to our Texas Generation reporting unit. Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight line basis.
Identifiable Intangible Assets and Liabilities
Identifiable intangible assets are comprised of the following:
| September 30, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||
| Identifiable Intangible Asset | Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | ||||||||||||||||||||||||||||||||
| Retail customer relationship | $ | 2,085 | $ | 1,733 | $ | 352 | $ | 2,083 | $ | 1,631 | $ | 452 | ||||||||||||||||||||||||||
| Software and other technology-related assets | 460 | 247 | 213 | 421 | 206 | 215 | ||||||||||||||||||||||||||||||||
| Retail and wholesale contracts | 233 | 204 | 29 | 248 | 206 | 42 | ||||||||||||||||||||||||||||||||
| Contractual service agreements (a) | 19 | 4 | 15 | 23 | 2 | 21 | ||||||||||||||||||||||||||||||||
| Other identifiable intangible assets (b) | 60 | 8 | 52 | 95 | 20 | 75 | ||||||||||||||||||||||||||||||||
| Total identifiable intangible assets subject to amortization | $ | 2,857 | $ | 2,196 | 661 | $ | 2,870 | $ | 2,065 | 805 | ||||||||||||||||||||||||||||
| Retail trade names (not subject to amortization) | 1,341 | 1,341 | ||||||||||||||||||||||||||||||||||||
| Total identifiable intangible assets | $ | 2,002 | $ | 2,146 |
(a)At September 30, 2022, amounts related to contractual service agreements that have become liabilities due to amortization of the economic impacts of the intangibles have been removed from both the gross carrying amount and accumulated amortization.
(b)Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).
Identifiable intangible liabilities are comprised of the following:
| Identifiable Intangible Liability | September 30, 2022 | December 31, 2021 | ||||||||||||
| Contractual service agreements | $ | 129 | $ | 125 | ||||||||||
| Purchase and sale of power and capacity | 3 | 8 | ||||||||||||
| Fuel and transportation purchase contracts | 10 | 14 | ||||||||||||
| Total identifiable intangible liabilities | $ | 142 | $ | 147 |
Expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the condensed consolidated statements of operations) consisted of:
| Identifiable Intangible Assets and Liabilities | Condensed Consolidated Statements of Operations | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||||
| Retail customer relationship | Depreciation and amortization | $ | 34 | $ | 49 | $ | 102 | $ | 147 | ||||||||||||||||||||
| Software and other technology-related assets | Depreciation and amortization | 17 | 20 | 53 | 58 | ||||||||||||||||||||||||
| Retail and wholesale contracts/purchase and sale/fuel and transportation contracts | Operating revenues/fuel, purchased power costs and delivery fees | (1) | 1 | 4 | (60) | ||||||||||||||||||||||||
| Other identifiable intangible assets | Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization | 109 | 91 | 296 | 196 | ||||||||||||||||||||||||
| Total intangible asset expense, net (a) | $ | 159 | $ | 161 | $ | 455 | $ | 341 |
(a)Amounts recorded in depreciation and amortization totaled $52 million and $70 million for the three months ended September 30, 2022 and 2021, respectively, and $157 million and $208 million for the nine months ended September 30, 2022 and 2021, respectively. Amounts exclude contractual services agreements. 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 our 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 and Liabilities
As of September 30, 2022, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.
| Year | Estimated Amortization Expense | |||||||
| 2022 | $ | 206 | ||||||
| 2023 | $ | 151 | ||||||
| 2024 | $ | 102 | ||||||
| 2025 | $ | 76 | ||||||
| 2026 | $ | 51 |
6. INCOME TAXES
Income Tax Expense
The calculation of our effective tax rate is as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Net income (loss) before income taxes | $ | 914 | $ | 41 | $ | (1,224) | $ | (2,563) | |||||||||||||||
| Income tax (expense) benefit | $ | (236) | $ | (31) | $ | 262 | $ | 569 | |||||||||||||||
| Effective tax rate | 25.8 | % | 75.6 | % | 21.4 | % | 22.2 | % |
For the three months ended September 30, 2022, the effective tax rate of 25.8% was higher than the U.S. federal statutory rate of 21% due primarily to the nondeductible impacts of the TRA and state income taxes. For the nine months ended September 30, 2022, the effective tax rate of 21.4% was higher than the U.S. federal statutory rate of 21% due primarily to the nondeductible impacts of the TRA and state income taxes.
For the three months ended September 30, 2021, the effective tax rate of 75.6% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA, additional valuation allowance against certain state net operating losses, and state income taxes. For the nine months ended September 30, 2021, the effective tax rate of 22.2% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes.
Inflation Reduction Act of 2022
In August 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA), which, among other things, implements substantial new and modified energy tax credits, including a nuclear production tax credit (PTC), a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% alternative minimum tax on book income of certain large corporations, and a 1% excise tax on net stock repurchases. Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months. The corporate alternative minimum tax is not applicable in our next fiscal year since it is based on a three-year average annual adjusted financial statement income in excess of $1 billion. The excise tax is not expected to have a material impact on our financial statements. We have taken the corporate alternative minimum tax and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes for periods after the law takes effect and for estimating the TRA liability.
Coronavirus Aid, Relief, and Economic Security Act (CARES Act) and Final Section 163(j) Regulations
In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. The CARES Act provides numerous relief provisions for corporate taxpayers, including modification of the utilization limitations on net operating losses, favorable expansion of the deduction for business interest expense under IRC Section 163(j) (Section 163(j)), the ability to accelerate timing of refundable alternative minimum tax (AMT) credits and the temporary suspension of certain payment requirements for the employer portion of social security taxes. Additionally, the final Section 163(j) regulations were issued in July 2020 and provided a critical correction to the proposed regulations with respect to the computation of adjusted taxable income. As of January 1, 2022, certain provisions in the final Section 163(j) regulations have sunset, including the addback of depreciation and amortization to adjusted taxable income. As a result, under the law as currently drafted, Vistra's deductible business interest expense will be significantly limited for the 2022 tax year. Vistra remains active in legislative monitoring and advocacy efforts to support a legislative solution to reinstate and make permanent the addback of depreciation and amortization to adjusted taxable income. Vistra is also utilizing the CARES Act payroll deferral mechanism to defer the payment of approximately $22 million from 2020 to 2021 and 2022. We paid approximately half of the previously deferred taxes in December 2021.
Liability for Uncertain Tax Positions
Vistra and its subsidiaries file income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject to examinations by the IRS and other taxing authorities. In February 2021, Vistra was notified that the IRS had opened a federal income tax audit for tax years 2018 and 2019 and an employment tax audit for tax year 2018. In the second quarter of 2022, the employment tax audit for tax year 2018 was closed with no adjustment. Crius is currently under audit by the IRS for the tax years 2015 and 2016. Uncertain tax positions totaled $37 million and $38 million at September 30, 2022 and December 31, 2021, respectively.
7. TAX RECEIVABLE AGREEMENT OBLIGATION
On the Effective Date, Vistra entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of certain former first-lien creditors of TCEH. 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 (a) 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), (b) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (c) 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.
Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien secured creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Such TRA Rights are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 15).
The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets, for the nine months ended September 30, 2022 and 2021:
| Nine Months Ended September 30, | |||||||||||
| 2022 | 2021 | ||||||||||
| TRA obligation at the beginning of the period | $ | 395 | $ | 450 | |||||||
| Accretion expense | 50 | 48 | |||||||||
| Changes in tax assumptions impacting timing of payments (a) | (21) | (79) | |||||||||
| Impacts of Tax Receivable Agreement | 29 | (31) | |||||||||
| TRA obligation at the end of the period | 424 | 419 | |||||||||
| Less amounts due currently | (1) | (3) | |||||||||
| Noncurrent TRA obligation at the end of the period | $ | 423 | $ | 416 |
(a)During the three months ended September 30, 2022, we recorded a decrease to the carrying value of the TRA obligation totaling $104 million as a result of adjustments to forecasted taxable income due to decreases in commodity price forecasts and impacts of the IRA. During the nine months ended September 30, 2022, we recorded a decrease to the carrying value of the TRA obligation totaling $21 million as a result of adjustments to forecasted taxable income due to impacts of the IRA, partially offset by increases in commodity price forecasts. During the three months ended September 30, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $51 million as a result of adjustments to forecasted taxable income and anticipated tax benefits available under current tax laws for planned additional renewable development projects, particularly in light of the passage of Illinois’ coal-to-solar legislation. During the nine months ended September 30, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $79 million as a result of adjustments to forecasted taxable income including the financial impacts of Winter Storm Uri, and anticipated tax benefits available under current tax laws for planned additional renewable development projects.
As of September 30, 2022, the estimated carrying value of the TRA obligation totaled $424 million, which represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 21%, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra now operates in, including the relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business. The estimates of future business results include assumptions related to renewable development projects that Vistra is planning to execute that generate significant tax benefits. These benefits have a material impact on the timing of TRA obligation payments. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of September 30, 2022, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion, with more than half of such amount expected to be paid during the next 15 years, and the final payment expected to be made around the year 2056 (if the TRA is not terminated earlier pursuant to its terms).
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation.
8. 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, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Net income (loss) attributable to Vistra | $ | 668 | $ | 7 | $ | (981) | $ | (2,000) | |||||||||||||||
| Less cumulative dividends attributable to Series A Preferred Stock | (20) | — | (60) | — | |||||||||||||||||||
| Less cumulative dividends attributable to Series B Preferred Stock | (17) | — | (52) | — | |||||||||||||||||||
| Net income (loss) attributable to common stock — basic | 631 | 7 | (1,093) | (2,000) | |||||||||||||||||||
| Weighted average shares of common stock outstanding — basic | 413,762,896 | 482,516,965 | 431,381,151 | 483,150,213 | |||||||||||||||||||
| Net income (loss) per weighted average share of common stock outstanding — basic | $ | 1.53 | $ | 0.01 | $ | (2.53) | $ | (4.14) | |||||||||||||||
| Dilutive securities: Stock-based incentive compensation plan | 3,719,615 | 1,977,581 | — | — | |||||||||||||||||||
| Weighted average shares of common stock outstanding — diluted | 417,482,511 | 484,494,546 | 431,381,151 | 483,150,213 | |||||||||||||||||||
| Net income (loss) per weighted average share of common stock outstanding — diluted | $ | 1.51 | $ | 0.01 | $ | (2.53) | $ | (4.14) |
Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 1,757,365 and 12,851,055 shares for the three months ended September 30, 2022 and 2021, respectively, and 8,076,314 and 15,223,763 shares for the nine months ended September 30, 2022 and 2021, respectively.
9. 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). The Receivables Facility was renewed in July 2022, extending the term of the Receivables Facility to July 2023, adjusting the commitment of the purchasers to purchase interests in the receivables under the Receivables Facility during certain periods to align with the peak retail season and increasing the commitments by $25 million for the settlement periods through December 2022 as compared to prior year periods, as follows: (i) $625 million beginning with the settlement date in July 2022 until the settlement date in August 2022, (ii) $750 million from the settlement date in August 2022 until the settlement date in November 2022, (iii) $625 million from the settlement date in November 2022 until the settlement date in December 2022, and (iv) $600 million from the settlement date in December 2022 and thereafter for the remaining term of the Receivables Facility.
In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands 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 limits 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 obligations under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings on the condensed consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our 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, 2022, outstanding borrowings under the Receivables Facility totaled $625 million and were supported by $1.172 billion of RecCo gross receivables. As of December 31, 2021, 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 2022, the Repurchase Facility was renewed until July 2023 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 Transactions). Each 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, 2022 and December 31, 2021.
10. DEBT
Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company.
| September 30, 2022 | December 31, 2021 | ||||||||||
| Vistra Operations Credit Facilities | $ | 2,522 | $ | 2,543 | |||||||
| 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 | 1,500 | |||||||||
| 5.125% Senior Secured Notes, due May 13, 2025 | 1,100 | — | |||||||||
| 3.700% Senior Secured Notes, due January 30, 2027 | 800 | 800 | |||||||||
| 4.300% Senior Secured Notes, due July 15, 2029 | 800 | 800 | |||||||||
| Total Vistra Operations Senior Secured Notes | 4,600 | 3,100 | |||||||||
| 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 | |||||||||
| Total Vistra Operations Senior Unsecured Notes | 4,850 | 4,850 | |||||||||
| Other: | |||||||||||
| Forward Capacity Agreements | — | 213 | |||||||||
| Equipment Financing Agreements | 90 | 92 | |||||||||
| Other | — | 6 | |||||||||
| Total other long-term debt | 90 | 311 | |||||||||
| Unamortized debt premiums, discounts and issuance costs | (77) | (73) | |||||||||
| Total long-term debt including amounts due currently | 11,985 | 10,731 | |||||||||
| Less amounts due currently | (38) | (254) | |||||||||
| Total long-term debt less amounts due currently | $ | 11,947 | $ | 10,477 |
There were no outstanding short-term borrowings under the Commodity-Linked Facility and the Revolving Credit Facility (described below) as of both September 30, 2022 and December 31, 2021.
Vistra Operations Credit Facilities and Commodity-Linked Revolving Credit Facility
Vistra Operations Credit Facilities — As of September 30, 2022, the Vistra Operations Credit Facilities consisted of up to $6.247 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $3.725 billion (Revolving Credit Facility) and term loans of $2.522 billion (Term Loan B-3 Facility).
On April 29, 2022 (April 2022 Amendment Effective Date) and July 18, 2022 (July 2022 Amendment Effective Date), Vistra Operations entered into amendments (Credit Agreement Amendments) to the Vistra Operations Credit Agreement, among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, Credit Suisse AG, Cayman Island Branch, as administrative agent and collateral agent, and the other parties named therein. Pursuant to the Credit Agreement Amendments, new classes of extended revolving credit commitments maturing in April 2027 were established in aggregate amounts of $2.8 billion and $725 million as of the April 2022 Amendment Effective Date and the July 2022 Amendment Effective Date, respectively. After giving effect to the Credit Agreement Amendments, the aggregate amount of revolving commitments maturing on April 29, 2027 equals $3.525 billion (Extended Revolving Credit Facility), while the $200 million in revolving commitments maturing on June 14, 2023 (Non-Extended Revolving Credit Facility) remain unchanged by the Credit Agreement Amendments. The July 18, 2022 amendment to the Vistra Operations Credit Agreement also provides that Vistra Operations will terminate at least $350 million in Extended Revolving Credit Facility commitments by December 30, 2022 or earlier if Vistra Operations or any guarantor receives proceeds from any capital markets transaction whose primary purpose is designed to enhance the liquidity of Vistra Operations and its guarantors. Furthermore, the Credit Agreement Amendments appoint new revolving letter of credit issuers, such that the aggregate amount of revolving letter of credit commitments equals $3.245 billion after giving effect to the Credit Agreement Amendments. Fees and expenses related to the Credit Agreement Amendments totaled $7 million and $8 million in the three and nine months ended September 30, 2022, respectively, which were capitalized as a reduction in the carrying amount of the debt.
In March 2021, Vistra Operations borrowed $1.0 billion principal amount under the Term Loan A Facility. In April 2021, Vistra Operations borrowed an additional $250 million principal amount under the Term Loan A Facility. Proceeds from the Term Loan A Facility, together with cash on hand, were used to repay certain amounts outstanding under the Revolving Credit Facility. Borrowings under the Term Loan A Facility were reported in short-term borrowings in our condensed consolidated balance sheet. In May 2021, Vistra Operations used the proceeds from the issuance of the Vistra Operations 4.375% senior unsecured notes due 2029 (described below), together with cash on hand, to repay the $1.250 billion borrowings under the Term Loan A Facility. We recorded an extinguishment loss of $1 million on the transaction in the nine months ended September 30, 2021.
Our credit facilities and related available capacity as of September 30, 2022 are presented below.
| September 30, 2022 | ||||||||||||||||||||||||||||||||
| Credit Facilities | Maturity Date | Facility Limit | Cash Borrowings | Letters of Credit Outstanding | Available Capacity | |||||||||||||||||||||||||||
| Extended Revolving Credit Facility (a) | April 29, 2027 | $ | 3,525 | $ | — | $ | 2,388 | $ | 1,137 | |||||||||||||||||||||||
| Non-Extended Revolving Credit Facility (b) | June 14, 2023 | 200 | — | 135 | 65 | |||||||||||||||||||||||||||
| Term Loan B-3 Facility (c) | December 31, 2025 | 2,522 | 2,522 | — | — | |||||||||||||||||||||||||||
| Total Vistra Operations Credit Facilities | $ | 6,247 | $ | 2,522 | $ | 2,523 | $ | 1,202 | ||||||||||||||||||||||||
| Commodity-Linked Facility (d) | October 5, 2022 | $ | 2,250 | $ | — | $ | — | $ | 1,701 | |||||||||||||||||||||||
| Total Credit Facilities | $ | 8,497 | $ | 2,522 | $ | 2,523 | $ | 2,903 |
(a)Extended Revolving Credit Facility used for general corporate purposes. Cash borrowings under the Extended Revolving Credit Facility are reported in short-term borrowings in our condensed consolidated balance sheets. The full amount of Extended Revolving Credit Facility available capacity can be utilized to issue letters of credit.
(b)Non-Extended Revolving Credit Facility used for general corporate purposes. Cash borrowings under the Non-Extended Revolving Credit Facility are reported in short-term borrowings in our condensed consolidated balance sheets. The full amount of Non-Extended Revolving Credit Facility available capacity can be utilized to issue letters of credit.
(c)Cash borrowings under the Term Loan B-3 Facility are subject to a required scheduled quarterly payment in annual amount equal to 1.00% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed.
(d)Commodity-Linked Facility (defined below) used to support our comprehensive hedging strategy. As of September 30, 2022, available capacity reflects the borrowing base which is lower than the aggregate commitments of $2.25 billion. The Commodity-Linked Facility was amended in October 2022, decreasing the aggregate commitments to $1.35 billion and extending the term to October 2023. Cash borrowings under the Commodity-Linked Facility are reported in short-term borrowings in our condensed consolidated balance sheets.
Under the Vistra Operations Credit Agreement, the interest applicable to the Extended Revolving Credit Facility is based on a term Secured Overnight Financing Rate (SOFR), plus a spread that will range from 1.25% to 2.00%, based on the ratings of Vistra Operations' senior secured long-term debt securities, and the fee on any undrawn amounts with respect to the Extended Revolving Credit Facility had been revised to range from 17.5 basis points to 35.0 basis points, based on ratings of Vistra Operations' senior secured long-term debt securities. As of September 30, 2022, there were no outstanding borrowings under the Extended Revolving Credit Facility. Letters of credit issued under the Extended Revolving Credit Facility bear interest of 1.75%. The applicable interest rate margins for the Extended Revolving Credit Facility and the fee for undrawn amounts relating to such extended commitments may further be adjusted from time to time dependent upon the Company's performance relative to certain sustainability-linked targets and thresholds, as further described in the Vistra Operations Credit Agreement.
Under the Vistra Operations Credit Agreement, cash borrowings under the Non-Extended Revolving Credit Facility bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%. As of September 30, 2022, there were no outstanding borrowings under the Non-Extended Revolving Credit Facility. Letters of credit issued under the Non-Extended Revolving Credit Facility bear interest of 1.75%. Amounts borrowed under the Term Loan B-3 Facility bears interest based on applicable LIBOR rates plus fixed spreads of 1.75%. As of September 30, 2022, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 4.84% under the Term Loan B-3 Facility. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit and availability fees payable with respect to any unused portion of the available Non-Extended Revolving Credit Facility.
Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of 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 April 29, 2027 (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 to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements met 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, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 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, a total net leverage ratio not to exceed 5.50 to 1.00). As of September 30, 2022, we were in compliance with this financial covenant. 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.
Commodity-Linked Revolving Credit Facility — In order to support our comprehensive hedging strategy, in February 2022, Vistra Operations entered into a $1.0 billion senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent. In May 2022, we entered into an amendment to the Commodity-Linked Facility to increase the aggregate available commitments from $1.0 billion to $2.0 billion and to provide the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility by an additional $1.0 billion to a facility size of $3.0 billion. Subsequent amendments in May 2022 and June 2022 increased the aggregate available commitments from $2.0 billion to $2.25 billion.
On October 5, 2022, Vistra initiated an amendment to the Commodity-Linked Facility to, among other things, (i) extend the maturity date to October 4, 2023 and (ii) reduce the aggregate available commitments to $1.25 billion. On October 21, 2022, the Commodity-Linked Facility was further amended to increase the aggregate available commitments to $1.35 billion.
Fees and expenses related to the facility totaled zero and $4 million in the three and nine months ended September 30, 2022, respectively, which were capitalized as a reduction in the carrying amount of the debt.
Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero. Vistra Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce outstanding borrowings to be less than or equal to the borrowing base. Vistra Operations intends to use any borrowings provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capital and general corporate purposes.
Interest Rate Swaps — Vistra employs interest rate swaps to hedge our exposure to variable rate debt. As of September 30, 2022, Vistra has entered into the following series of interest rate swap transactions.
| Notional Amount | Expiration Date | Rate Range | ||||||||||||||||||||||||
| Swapped to fixed | $3,000 | July 2023 | 3.67 | % | - | 3.91% | ||||||||||||||||||||
| Swapped to variable | $700 | July 2023 | 3.20 | % | - | 3.23% | ||||||||||||||||||||
| Swapped to fixed | $720 | February 2024 | 3.71 | % | - | 3.72% | ||||||||||||||||||||
| Swapped to variable | $720 | February 2024 | 3.20 | % | - | 3.20% | ||||||||||||||||||||
| Swapped to fixed (a) | $3,000 | July 2026 | 4.72 | % | - | 4.79% | ||||||||||||||||||||
| Swapped to variable | $700 | July 2026 | 3.28 | % | - | 3.33% |
(a)Effective from July 2023 through July 2026.
During 2019, Vistra entered into $2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixed rate. The terms of these new swaps were matched against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms. The remaining existing swaps continue to hedge our exposure on $2.30 billion of debt through July 2026.
Secured Letter of Credit Facilities
In August and September 2020, Vistra entered into uncommitted standby letter of credit facilities that are each secured by a first lien on substantially all of Vistra Operations' (and its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities) (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are used for general corporate purposes. In October 2021, September 2022 and October 2022, Vistra entered into additional Secured LOC Facilities which are used for general corporate purposes. As of September 30, 2022, $517 million of letters of credit were outstanding under the Secured LOC Facilities.
Vistra Operations Senior Secured Notes
In May 2022, Vistra Operations issued $1.5 billion aggregate principal amount of senior secured notes (May 2022 Senior Secured Notes), consisting of $400 million aggregate principal amount of 4.875% senior secured notes due 2024 (4.875% Senior Secured Notes) and $1.1 billion aggregate principal amount of 5.125% senior secured notes due 2025 (5.125% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act (Senior Secured Notes Offering). The May 2022 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers. The 4.875% Senior Secured Notes mature in May 2024 and the 5.125% Senior Secured Notes mature in May 2025. Interest on the May 2022 Senior Secured Notes is payable in cash semiannually in arrears on May 13 and November 13 of each year, beginning in November 2022. Net proceeds from the Senior Secured Notes Offering totaling $1.485 billion, together with cash on hand, were used to pay down borrowings under the Commodity-Linked Facility. Fees and expenses related to the offering totaled $17 million in the nine months ended September 30, 2022, which were capitalized as a reduction in the carrying amount of the debt.
In 2019, Vistra Operations issued and sold $3.1 billion aggregate principal amount of 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 3.700% senior secured notes due 2027, the 4.300% senior secured notes due 2029 and the May 2022 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.
Vistra Operations Senior Unsecured Notes
In May 2021, Vistra Operations issued and sold $1.25 billion aggregate principal amount of 4.375% senior unsecured notes due 2029 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The 4.375% senior unsecured notes due 2029 were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P. Morgan Securities LLC, as representative of the several initial purchasers. The 4.375% senior unsecured notes mature in May 2029, with interest payable in arrears on May 1 and November 1 beginning November 1, 2021 with interest accrued from May 10, 2021. Net proceeds, together with cash on hand, were used to repay all amounts outstanding under the Term Loan A Facility and to pay fees and expenses of $15 million related to the offering.
Since 2018, Vistra Operations has issued and sold $4.85 billion aggregate principal amount of senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The 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 and the 4.375% senior unsecured notes due 2029 (collectively, as each may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) 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.
Debt Repurchase Program
In March 2021, the Board authorized up to $1.8 billion to voluntarily repay or repurchase outstanding debt, which authorization expired in March 2022 (the Prior Authorization). Through September 30, 2022, no amounts had been repurchased under the Prior Authorization. In October 2022, the Board re-authorized the voluntary repayment or repurchase of up to $1.8 billion of outstanding debt, with such authorization expiring on December 31, 2023.
Other Long-Term Debt
Forward Capacity Agreements — In March 2021, the Company sold a portion of the PJM capacity that cleared for Planning Years 2021-2022 to a financial institution (2021-2022 Forward Capacity Agreement). The buyer in this transaction received capacity payments from PJM during the Planning Years 2021-2022 in the amount of approximately $515 million. In May 2022, the final capacity payment from PJM during the Planning Years 2021-2022 was paid, and the terms of the 2021-2022 Forward Capacity were fulfilled.
On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a financial institution (Legacy Forward Capacity Agreements, and, together with the 2021-2022 Forward Capacity Agreement, the Forward Capacity Agreements). In May 2021, the final capacity payment from PJM during the Planning Years 2020-2021 was paid, and the terms of the Legacy Forward Capacity were fulfilled.
Maturities
Long-term debt maturities at September 30, 2022 are as follows:
| September 30, 2022 | |||||
| Remainder of 2022 | $ | 19 | |||
| 2023 | 40 | ||||
| 2024 | 1,940 | ||||
| 2025 | 3,567 | ||||
| 2026 | 1,006 | ||||
| Thereafter | 5,490 | ||||
| Unamortized premiums, discounts and debt issuance costs | (77) | ||||
| Total long-term debt, including amounts due currently | $ | 11,985 |
11. COMMITMENTS AND CONTINGENCIES
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below.
Letters of Credit
At September 30, 2022, we had outstanding letters of credit totaling $3.040 billion as follows:
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$2.635 billion to support commodity risk management 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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$247 million to support battery and solar development projects;
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$27 million to support executory contracts and insurance agreements;
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$74 million to support our REP financial requirements with the PUCT, and
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$57 million for other credit support requirements.
Surety Bonds
At September 30, 2022, we had outstanding surety bonds totaling $693 million to support performance under various contracts and legal obligations in the normal course of business.
Litigation and Regulatory Proceedings
Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material.
Gas Index Pricing Litigation — We, through our subsidiaries, and other companies have been named as defendants in lawsuits 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. We now remain as a defendant in only one action, which is a consolidated putative class action lawsuit pending in federal court in Wisconsin where a class has been certified and an interlocutory appeal has been filed in the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit Court).
Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius in July 2019. The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 5-year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint.
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. We filed our opening brief in June 2021, and response briefs were filed in September 2021. Oral argument was held in April 2022. In our brief, we argue that the prior PUCT rushed to adopt a rule that dramatically raised the price of electricity in ERCOT, but in doing so failed to follow any of the rulemaking procedures required for the PUCT to undertake an emergency rulemaking, and we have asked the court to vacate this rule. Other parties also filed briefs in support of our challenge to the PUCT's orders. In addition, we have also submitted settlement disputes with ERCOT over power prices and other issues during Winter Storm Uri. Following an appeal of the PUCT's March 5, 2021 verbal order and other statements made by the PUCT, the Texas Attorney General, on behalf of the PUCT, its client, represented in a letter agreement filed with the Third Court of Appeals that we and other parties may continue disputing the pricing during Winter Storm Uri through the ERCOT process and, to the extent the outcome of that process comes before the PUCT for review, the PUCT has not prejudged or made a final decision on that matter.
Koch Disputes — In March 2021, we filed a lawsuit in Texas state court against Odessa-Ector Power Partners, L.P., Koch Resources, LLC, Koch AG & Energy Solutions, LLC, and Koch Energy Services, LLC (Koch) seeking equitable relief in which we contested the amount of the February 2021 earnout payment under the terms of the 2017 asset purchase agreement (APA) with Koch. Koch subsequently filed its own related lawsuit in Delaware Chancery Court, and the Delaware Chancery Court ruled that all claims related to the APA dispute (including our equitable claims) would proceed in Delaware. We contested Koch's demand for $286 million for the February 2021 earnout payment as an unjust windfall and inconsistent with the parties' intent when they entered into the APA in 2017. In the three months ended March 31, 2021, we recorded a $286 million liability in other noncurrent liabilities and deferred credits in our condensed consolidated balance sheets. In March 2021, we also filed a lawsuit in New York state court against Koch for breach of contract and ineffective notice of force majeure related to Koch's failure to deliver contracted-for quantities of gas during Winter Strom Uri, which Koch removed to federal court. In November 2021, the disputes we had with Koch were resolved to the parties' mutual satisfaction and all the lawsuits have been dismissed. The matter was resolved within the amount that was reserved and was paid in the second quarter of 2022.
Brazos Electric Cooperative Inc. (Brazos) Bankruptcy — As a result of the lengthy period of peak pricing administratively imposed by the PUCT during Winter Storm Uri, certain market participants within ERCOT were not able to pay their full obligations to ERCOT. Consequently, ERCOT was "short-paid" approximately $2.9 billion, the majority of which was related to Brazos, a Texas-based non-profit electric cooperative corporation that provides wholesale electricity to its members, which, in turn, provide retail electricity to Texas consumers. In March 2021, Brazos commenced a Chapter 11 bankruptcy case in the U.S. Bankruptcy Court for the Southern District of Texas. As part of the Brazos bankruptcy proceeding, ERCOT filed a claim to recover approximately $1.9 billion from Brazos. In response, Brazos filed an adversary proceeding against ERCOT seeking to disallow or greatly reduce ERCOT's claim. ERCOT and Brazos subsequently engaged in mediation seeking to resolve the dispute as an alternative to ERCOT's imposition of its market default protocols which specify recovery of these losses through issuance of default uplift invoices to all market participants. Under this short-pay recovery process, uplifted short-paid amounts are allocated to all market participants based on market share on a monthly basis until the full short-paid amounts are recovered. The ERCOT protocols limit the amount of short-paid amounts that ERCOT can uplift to the entire market to $2.5 million per month which would have taken approximately 63 years to recover the full Brazos short-pay claim. As a result of applying these standard ERCOT market default protocols, we recognized an approximately $189 million default uplift liability in the first quarter of 2021 based on our market share which was subsequently reduced in the second quarter of 2021 to $124 million as ERCOT collected amounts owed from certain defaulting entities through other means, primarily through securitization. The $124 million remaining default uplift liability relates entirely to our estimated share over time of the Brazos short pay to ERCOT.
After extensive negotiations, Brazos and ERCOT reached a settlement in September 2022 that is incorporated in a proposed Brazos plan of reorganization filed with the bankruptcy court. Under the settlement, Brazos will make two payments to ERCOT upon its emergence from bankruptcy: first, an approximately $600 million payment, which ERCOT will use to replenish its Congestion Revenue Rights (CCR) Reserve Account and pay down its portion of the securitization program adopted by the legislature for electric cooperatives and municipal-owned utilities, and second, an approximately $554 million payment to fund an initial distribution to be made by ERCOT to market participants with claims against the Brazos short-pay based on each market participant's payment election. Brazos will also make certain installment payments (of up to $13.8 million per year over 12 years) and contribute a portion of the proceeds from the sale of its generation assets (approximately $117 million) to fund payments, to be distributed by ERCOT, to the applicable market participants. Importantly, the settlement precludes ERCOT from collecting default uplift from market participants for any prepetition amounts owed by Brazos (i.e., it supplants the process to uplift the short-pay claim to market participants), and, if approved, would allow Vistra to extinguish the remaining $124 million default uplift liability to ERCOT on account of the Brazos short pay. In September 2022, Brazos filed its plan of reorganization with the bankruptcy court and the proposed ERCOT settlement agreement is subject to the Brazos bankruptcy plan voting and confirmation processes, which is anticipated to conclude in November 2022.
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 number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. 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 a MDL for pretrial 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 court heard oral argument on those motions in October 2022. We believe we have strong defenses to these lawsuits and intend to defend against these cases vigorously.
Climate Change
In January 2021, the Biden administration issued a series of Executive Orders, including one titled Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (the Environment Executive Order) which directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take action where the previous administration's action conflicts with national objectives. Several of the EPA agency actions discussed below are now subject to this review.
Greenhouse Gas Emissions
In July 2019, the EPA finalized a rule that repealed the Clean Power Plan (CPP) that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. In response to challenges brought by environmental groups and certain states, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the ACE rule, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. In October 2021, the U.S. Supreme Court granted four petitions for certiorari of the D.C. Circuit Court's decision and consolidated the cases for review. In June 2022, the U.S. Supreme Court issued an opinion reversing the D.C. Circuit Court's decision, and finding that the EPA exceeded its authority under Section 111 of the Clean Air Act when the EPA set emission requirements in the CPP based on generation shifting. In October 2022, the parties filed motions to govern in light of the U.S. Supreme Court's decision. In addition, the EPA has opened a docket seeking input on questions related to the regulation of GHGs under Section 111(d).
Cross-State Air Pollution Rule (CSAPR)
In April 2022, the EPA proposed a revised version of the CSAPR to address the 2015 ozone National Ambient Air Quality Standards (NAAQS). The rule would apply to 25 states beginning with the 2023 ozone seasons. States where Vistra operates generation units that would be subject to this proposed rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia and West Virginia. The revised Group 3 trading program (previously established in the Revised CSAPR Update Rule) would include emission budgets that the EPA says are achievable through existing controls installed at power plants. Starting in 2026, the budgets would be based on levels achieved through installation of selective catalytic reduction (SCR) controls at the approximately 20% of large coal-fueled power plants that do not currently have such controls. Starting in 2025, the budgets would be updated annually to account for source retirements. Starting in 2024, the rule would also impose a daily emissions rate limit for coal-fired units with existing controls and would impose such a limit for units installing new controls in 2027. 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. The EPA is expected to finalize a rule by early 2023. We cannot predict the outcome of the final rule or the effects of the final rule on operations of our generation fleet.
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 State Implementation Plan (SIP) and a partial Federal Implementation Plan (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 generating 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 BART rule is subject to the Environment Executive Order discussed above, and the EPA has stated it is starting a proceeding for reconsideration of the BART rule. The challenges in the D.C. Circuit Court have been held in abeyance pending the EPA's action on reconsideration.
SO2 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 U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the EPA's representation that it intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for reconsideration to the EPA. 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 August 2020, the EPA issued a Finding of Failure for Texas to submit an attainment plan. 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.
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 August 2017, the EPA announced that its reconsideration of the ELG rule would be limited to a review of the effluent limitations applicable to FGD and bottom ash wastewaters and the agency subsequently postponed the earliest compliance dates in the ELG rule for the application of effluent limitations for FGD and bottom ash wastewaters. Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in abeyance challenges to those effluent limitations. The remainder of the case proceeded, and 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. In July 2021, the EPA announced its intent to revise the ELG rule and moved to hold the 2020 ELG revision litigation in abeyance pending the EPA's completion of its reconsideration rulemaking. 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.
Coal Combustion Residuals (CCR)/Groundwater
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 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, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In November 2020, environmental groups petitioned for review of this rule in the D.C. Circuit Court, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Also, in November 2020, the EPA finalized a rule that would allow an alternative liner demonstration for certain qualifying facilities. In November 2020, we submitted an alternate liner demonstration for one CCR unit at Martin Lake. In August 2021, we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following announcement that Zimmer will close by May 31, 2022. 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. The EPA issued these new purported requirements without prior notice and without following the legal requirements for adopting new rules. These new purported requirements announced by the EPA are contrary to existing regulations and the EPA's prior positions. 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 intend to ask 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 have intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various environmental groups have intervened on behalf of the EPA.
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 May 2018, Prairie Rivers Network (PRN) filed a citizen suit in federal court in Illinois against DMG, alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. In June 2021, the Seventh Circuit Court affirmed the district court's dismissal of the lawsuit, but stated that PRN may refile. In April 2019, PRN also filed a complaint against DMG before the IPCB, alleging that groundwater flows allegedly associated with the ash impoundments at the Vermilion site have resulted in exceedances both of surface water standards and Illinois groundwater standards dating back to 1992. We answered that complaint in July 2021, and this matter remains in the very early stages.
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 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 newly implemented 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. These proposed closure costs are reflected in the ARO in our condensed consolidated balance sheets (see Note 17).
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 filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule. We filed our opening brief in October 2021. Other parties have also filed appeals of certain provisions of the final rule. 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 six of our sites in July 2022. One additional closure construction application will be filed for our Baldwin facility in 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. However, the currently anticipated CCR surface impoundment and landfill closure costs, as reflected in our existing ARO liabilities, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location.
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. The Company intends to reply substantively to this submission, and to vigorously defend its position, by March 1, 2023 consistent with FERC's scheduling orders.
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.
12. EQUITY
Share Repurchase Programs
Current Share Repurchase Program — In October 2021, we announced that the Board authorized a share repurchase program (Share Repurchase Program) under which up to $2.00 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021, at which time it superseded the 2020 Share Repurchase Program (described below) and any authorization remaining as of such date. On August 4, 2022, the Board authorized an incremental $1.25 billion for repurchases to bring the total authorized under the Share Repurchase Program to $3.25 billion.
In the three and nine months ended September 30, 2022, shares of common stock repurchased under the Share Repurchase Program totaled 16,797,963 and 63,459,123, respectively, for approximately $407 million and $1.493 billion, respectively, at an average price per share of common stock of $24.21 and $23.52, respectively. Shares repurchased include 850,349 of unsettled shares repurchased for $18 million as of September 30, 2022. As of September 30, 2022, approximately $1.348 billion of the total authorized of $3.25 billion was available for additional repurchases under the Share Repurchase Program.
From October 1, 2022 through November 1, 2022, 7,076,619 of our common stock had been repurchased under the Share Repurchase Program for $156 million at an average price per share of common stock of $22.04, and at November 1, 2022, approximately $1.192 billion of the total authorized of $3.25 billion was available for repurchases under the 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 certificate of designation of the Series A Preferred Stock and the Series B Preferred Stock, respectively.
Superseded Share Repurchase Program — In September 2020, we announced that the Board authorized a share repurchase program (2020 Share Repurchase Program) under which up to $1.5 billion of our outstanding shares of common stock may be repurchased. The 2020 Share Repurchase Program was effective on January 1, 2021. No shares were repurchased in the three months ended September 30, 2021. In the nine months ended September 30, 2021, 8,658,153 shares of our common stock were repurchased under the 2020 Share Repurchase Program for approximately $175 million at an average price of $20.21 per share of common stock. The 2020 Share Repurchase Program was superseded by the Share Repurchase Program described above in October 2021.
Preferred Stock
On October 15, 2021 (Series A Issuance Date), we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Series A Offering). The net proceeds of the Series A Offering were approximately $990 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Series A Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (described above).
On December 10, 2021 (Series B Issuance Date), we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering). The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments.
The Series A Preferred Stock and the Series B Preferred Stock are not convertible into or exchangeable for any other securities of the Company and have limited voting rights. The Series A Preferred Stock may be redeemed at the option of the Company at any time after the Series A First Reset Date (defined below) and in certain other circumstances prior to the Series A First Reset Date. The Series B Preferred Stock may be redeemed at the option of the Company at any time after the Series B First Reset Date (defined below) and in certain other circumstances prior to the Series B First Reset Date.
Dividends
Common Stock — 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.
In February 2021, April 2021, July 2021 and October 2021, the Board declared quarterly dividends of $0.15 per share of common stock that were paid in March 2021, June 2021, September 2021 and December 2021, respectively.
In February 2022, May 2022 and July 2022, the Board declared quarterly dividends of $0.17, $0.177, and $0.184 per share of common stock that were paid in March 2022, June 2022 and September 2022, respectively. In October 2022, the Board declared a quarterly dividend of $0.193 per share of common stock that will be paid in December 2022.
Preferred Stock — The annual dividend rate on each share of Series A Preferred Stock is 8.0% from the Issuance Date to, but excluding October 15, 2026 (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.
In February 2022 and July 2022, the Board declared semi-annual dividends of $40.00 per share of Series A Preferred Stock that were paid in April 2022 and October 2022, respectively.
The annual dividend rate on each share of Series B Preferred Stock is 7.0% from the Series B Issuance Date to, but excluding December 15, 2026 (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.
In May 2022, the Board declared a semi-annual dividend of $35.97 (including amounts accrued from December 10, 2021 to December 15, 2021) per share of Series B Preferred Stock that was paid in June 2022. In October 2022, the Board declared a semi-annual dividend of $35.00 per share of Series B Preferred Stock that will be paid in December 2022.
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, 2022, Vistra Operations can distribute approximately $5.0 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 $400 million and $75 million during the three months ended September 30, 2022 and 2021, respectively, and $1.350 billion and $405 million for the nine months ended September 30, 2022 and 2021, 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, 2022, 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 and the Series B 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) and Series B 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 and the Series B Preferred Stock, respectively.
Warrants
At the Merger Date, the Company entered into an agreement whereby the holder of each outstanding warrant previously issued by Dynegy would be entitled to receive, upon paying an exercise price of $35.00 (subject to adjustment from time to time), the number of shares of Vistra common stock that such holder would have been entitled to receive if it had held one share of Dynegy common stock at the closing of the Merger, or 0.652 shares of Vistra common stock. Accordingly, upon exercise, a warrant holder would effectively pay $53.68 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received. In January 2022, in accordance with the terms of the warrant agreement, the exercise price of each warrant was adjusted downward to $34.00 (subject to further adjustment from time to time), or $52.15 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received. As of September 30, 2022, nine million warrants expiring in 2024 were outstanding. The warrants were included in equity based on their fair value at the Merger Date.
Equity
The following table presents the changes to equity for the three months ended September 30, 2022:
| Preferred Stock | Common Stock (a) | Treasury Stock | Additional Paid-in Capital | Retained Earnings (Deficit) | Accumulated Other Comprehensive Income (Loss) | Total Stockholders' Equity | Noncontrolling Interest in Subsidiary | Total Equity | |||||||||||||||||||||||||||||||||||||||||||||
| Balance at June 30, 2022 | $ | 2,000 | $ | 5 | $ | (2,645) | $ | 9,890 | $ | (3,842) | $ | (16) | $ | 5,392 | $ | 11 | $ | 5,403 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (407) | — | — | — | (407) | — | (407) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (75) | — | (75) | — | (75) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (37) | — | (37) | — | (37) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 29 | — | — | 29 | — | 29 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | 668 | — | 668 | 10 | 678 | ||||||||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income (loss) | 6 | 6 | — | 6 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | 4 | 2 | 6 | (2) | 4 | |||||||||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2022 | $ | 2,000 | $ | 5 | $ | (3,052) | $ | 9,923 | $ | (3,284) | $ | (10) | $ | 5,582 | $ | 19 | $ | 5,601 |
The following table presents the changes to equity for the nine months ended September 30, 2022:
| Preferred Stock (a) | Common Stock (b) | Treasury Stock | Additional Paid-in Capital | Retained Earnings (Deficit) | Accumulated Other Comprehensive Income (Loss) | Total Stockholders' Equity | Noncontrolling Interest in Subsidiary | Total Equity | |||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | $ | 2,000 | $ | 5 | $ | (1,558) | $ | 9,824 | $ | (1,964) | $ | (16) | $ | 8,291 | $ | 1 | $ | 8,292 | |||||||||||||||||||||||||||||||||||
| Stock repurchases | — | — | (1,493) | — | — | — | (1,493) | — | (1,493) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | — | (227) | — | (227) | — | (227) | ||||||||||||||||||||||||||||||||||||||||||||
| Dividends declared on preferred stock | — | — | — | — | (113) | — | (113) | — | (113) | ||||||||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | — | 87 | — | — | 87 | — | 87 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | (981) | — | (981) | 19 | (962) | |||||||||||||||||||||||||||||||||||||||||||||
| Adoption of accounting standard | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income (loss) | — | — | — | — | — | 6 | 6 | — | 6 | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | (1) | 12 | 1 | — | 12 | (1) | 11 | ||||||||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2022 | $ | 2,000 | $ | 5 | $ | (3,052) | $ | 9,923 | $ | (3,284) | $ | (10) | $ | 5,582 | $ | 19 | $ | 5,601 |
(a)Authorized shares totaled 100,000,000 at September 30, 2022. Outstanding shares of Series A Preferred Stock totaled 1,000,000 at both September 30, 2022 and December 31, 2021 and outstanding shares of Series B Preferred Stock totaled 1,000,000 at both September 30, 2022 and December 31, 2021.
(b)Authorized shares totaled 1,800,000,000 at September 30, 2022. Outstanding common shares totaled 405,444,072 and 469,072,597 at September 30, 2022 and December 31, 2021, respectively. Treasury shares totaled 131,640,516 and 63,856,879 at September 30, 2022 and December 31, 2021, respectively.
The following table presents the changes to equity for the three months ended September 30, 2021:
| Common Stock (a) | Treasury Stock | Additional Paid-in Capital | Retained Earnings (Deficit) | Accumulated Other Comprehensive Income (Loss) | Total Stockholders' Equity | Noncontrolling Interest | Total Equity | ||||||||||||||||||||||||||||||||||||||||
| Balance at June 30, 2021 | $ | 5 | $ | (1,148) | $ | 9,816 | $ | (2,552) | $ | (45) | $ | 6,076 | $ | (8) | $ | 6,068 | |||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | (72) | — | (72) | — | (72) | |||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | 12 | — | — | 12 | — | 12 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 7 | — | 7 | 3 | 10 | |||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income (loss) | — | — | — | — | 14 | 14 | — | 14 | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | 1 | (2) | — | (1) | — | (1) | |||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2021 | $ | 5 | $ | (1,148) | $ | 9,829 | $ | (2,619) | $ | (31) | $ | 6,036 | $ | (5) | $ | 6,031 |
The following table presents the changes to equity for the nine months ended September 30, 2021:
| Common Stock (a) | Treasury Stock | Additional Paid-in Capital | Retained Earnings (Deficit) | Accumulated Other Comprehensive Income (Loss) | Total Stockholders' Equity | Noncontrolling Interest in Subsidiary | Total Equity | ||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | $ | 5 | $ | (973) | $ | 9,786 | $ | (399) | $ | (48) | $ | 8,371 | $ | (10) | $ | 8,361 | |||||||||||||||||||||||||||||||
| Stock repurchases | — | (175) | — | — | — | (175) | — | (175) | |||||||||||||||||||||||||||||||||||||||
| Dividends declared on common stock | — | — | — | (219) | — | (219) | — | (219) | |||||||||||||||||||||||||||||||||||||||
| Effects of stock-based incentive compensation plans | — | — | 39 | — | 39 | — | 39 | ||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | (2,000) | — | (2,000) | 6 | (1,994) | |||||||||||||||||||||||||||||||||||||||
| Change in accumulated other comprehensive income (loss) | — | — | — | — | 17 | 17 | — | 17 | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | 4 | (1) | — | 3 | (1) | 2 | |||||||||||||||||||||||||||||||||||||||
| Balance at September 30, 2021 | $ | 5 | $ | (1,148) | $ | 9,829 | $ | (2,619) | $ | (31) | $ | 6,036 | $ | (5) | $ | 6,031 |
(a)Authorized shares totaled 1,800,000,000 at September 30, 2021. Outstanding common shares totaled 482,551,344 and 489,305,888 at September 30, 2021 and December 31, 2020, respectively. Treasury shares totaled 49,701,377 and 41,043,224 at September 30, 2021 and December 31, 2020, respectively.
13. FAIR VALUE MEASUREMENTS
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra Chief Financial Officer.
Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 14 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
-
Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that are legally characterized as settlement of derivative contracts rather than collateral.
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Level 2 valuations utilize 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. We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observable. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors.
-
Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing delivery periods and locations and credit-related nonperformance risk assumptions. These inputs and valuation models are developed and maintained by employees trained and experienced in market operations and fair value measurements and validated by the Company's risk management group.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement.
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, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 (a) | Reclass (b) | Total | Level 1 | Level 2 | Level 3 (a) | Reclass (b) | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 5,152 | $ | 1,321 | $ | 1,157 | $ | 65 | $ | 7,695 | $ | 1,408 | $ | 889 | $ | 442 | $ | 5 | $ | 2,744 | |||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | — | 153 | — | — | 153 | — | 19 | — | — | 19 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust – equity securities (c) | 530 | — | — | — | 530 | 724 | — | — | 724 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust – debt securities (c) | — | 592 | — | 592 | — | 679 | — | 679 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Sub-total | $ | 5,682 | $ | 2,066 | $ | 1,157 | $ | 65 | 8,970 | $ | 2,132 | $ | 1,587 | $ | 442 | $ | 5 | 4,166 | |||||||||||||||||||||||||||||||||||||||||
| Assets measured at net asset value (d): | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust – equity securities (c) | 425 | 557 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 9,395 | $ | 4,723 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 6,678 | $ | 1,578 | $ | 2,188 | $ | 65 | $ | 10,509 | $ | 2,153 | $ | 650 | $ | 802 | $ | 5 | $ | 3,610 | |||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | — | 90 | — | — | 90 | — | 217 | — | — | 217 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | $ | 6,678 | $ | 1,668 | $ | 2,188 | $ | 65 | $ | 10,599 | $ | 2,153 | $ | 867 | $ | 802 | $ | 5 | $ | 3,827 |
(a)See table below for description of Level 3 assets and liabilities.
(b)Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our condensed consolidated balance sheets.
(c)The nuclear decommissioning trust investment is included in the other investments line in our condensed consolidated balance sheets. See Note 17.
(d)The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our condensed consolidated balance sheets. Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy.
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. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 14 for further discussion regarding derivative instruments.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
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 at September 30, 2022 and December 31, 2021:
| September 30, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Contract Type (a) | Assets | Liabilities | Total | Valuation Technique | Significant Unobservable Input | Range (b) | Average (b) | |||||||||||||||||||||||||||||||||||||||||||
| Electricity purchases and sales | $ | 912 | $ | (1,467) | $ | (555) | Income Approach | Hourly price curve shape (c) | $ | — | to | $70 | $36 | |||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Illiquid delivery periods for hub power prices and heat rates (d) | $ | 50 | to | $120 | $84 | |||||||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Options | — | (500) | (500) | Option Pricing Model | Gas to power correlation (e) | 15 | % | to | 100% | 57% | ||||||||||||||||||||||||||||||||||||||||
| Power and gas volatility (e) | 5 | % | to | 615% | 311% | |||||||||||||||||||||||||||||||||||||||||||||
| Financial transmission rights | 159 | (49) | 110 | Market Approach (f) | Illiquid price differences between settlement points (g) | $ | (35) | to | $10 | $(11) | ||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 47 | (162) | (115) | Income Approach | Gas basis and illiquid delivery periods (h) | $ | — | to | $30 | $13 | ||||||||||||||||||||||||||||||||||||||||
| MMBtu | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Coal | 29 | — | 29 | Income Approach | Probability of default (i) | —% | to | 40% | 20 | % | ||||||||||||||||||||||||||||||||||||||||
| Recovery rate (j) | —% | to | 40% | 20 | % | |||||||||||||||||||||||||||||||||||||||||||||
| Other (k) | 10 | (10) | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 1,157 | $ | (2,188) | $ | (1,031) |
| December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Contract Type (a) | Assets | Liabilities | Total | Valuation Technique | Significant Unobservable Input | Range (b) | Average (b) | |||||||||||||||||||||||||||||||||||||||||||
| Electricity purchases and sales | $ | 204 | $ | (470) | $ | (266) | Income Approach | Hourly price curve shape (c) | $ | — | to | $60 | $30 | |||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Illiquid delivery periods for hub power prices and heat rates (d) | $ | 20 | to | $140 | $80 | |||||||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Options | 1 | (209) | (208) | Option Pricing Model | Gas to power correlation (e) | 10 | % | to | 100% | 56% | ||||||||||||||||||||||||||||||||||||||||
| Power and gas volatility (e) | 5 | % | to | 490% | 248% | |||||||||||||||||||||||||||||||||||||||||||||
| Financial transmission rights | 122 | (34) | 88 | Market Approach (f) | Illiquid price differences between settlement points (g) | $ | (30) | to | $10 | $(9) | ||||||||||||||||||||||||||||||||||||||||
| MWh | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 29 | (86) | (57) | Income Approach | Gas basis (h) | $ | (1) | to | $16 | $8 | ||||||||||||||||||||||||||||||||||||||||
| MMBtu | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Coal | 61 | — | 61 | Income Approach | Probability of default (i) | —% | to | 40% | 20 | % | ||||||||||||||||||||||||||||||||||||||||
| Recovery rate (j) | —% | to | 40% | 20 | % | |||||||||||||||||||||||||||||||||||||||||||||
| Other (k) | 25 | (3) | 22 | |||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 442 | $ | (802) | $ | (360) |
(a)Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, ISO-NE, NYISO and MISO regions. The 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. Options consist of physical electricity options, spread options, swaptions and natural gas options.
(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 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 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 gas basis prices and fixed prices.
(i)Estimate of the range of probabilities of default based on past experience, the length of the contract, and both the Company's and the counterparty's credit ratings.
(j)Estimate of the default recovery rate based on historical corporate rates.
(k)Other includes contracts for environmental allowances.
See the table below for discussion of transfers between Level 2 and Level 3 for the three and nine months ended September 30, 2022 and 2021.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and nine months ended September 30, 2022 and 2021.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Net asset (liability) balance at beginning of period | $ | (1,015) | $ | 46 | $ | (360) | $ | 22 | |||||||||||||||
| Total unrealized valuation losses (a) | (235) | (174) | (1,256) | — | |||||||||||||||||||
| Purchases, issuances and settlements (b): | |||||||||||||||||||||||
| Purchases | 44 | 33 | 139 | 73 | |||||||||||||||||||
| Issuances | (6) | (12) | (48) | (22) | |||||||||||||||||||
| Settlements | 257 | (72) | 431 | (238) | |||||||||||||||||||
| Transfers into Level 3 (c) | (44) | (28) | (5) | (26) | |||||||||||||||||||
| Transfers out of Level 3 (c) | (32) | (17) | 68 | (33) | |||||||||||||||||||
| Net change (d) | (16) | (270) | (671) | (246) | |||||||||||||||||||
| Net liability balance at end of period | $ | (1,031) | $ | (224) | $ | (1,031) | $ | (224) | |||||||||||||||
| Unrealized valuation losses relating to instruments held at end of period | $ | (234) | $ | (224) | $ | (797) | $ | (240) |
(a)Includes net losses of $101 million and $263 million for the three months ended September 30, 2022 and 2021, respectively, and $967 million and $263 million for the nine months ended September 30, 2022 and 2021, respectively, recognized due to the discontinuance of NPNS accounting on retail electric contract portfolios in the third quarter of 2021 and second quarter of 2022 where physical settlement is no longer considered probable throughout the contract term.
(b)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.
(c)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 and nine months ended September 30, 2022, transfers into Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power, gas and coal derivatives where forward pricing inputs have become observable. For the three and nine months ended September 30, 2021, transfers out of Level 3 primarily consist of gas and power derivatives where forward pricing inputs have become observable.
(d)Activity excludes change in fair value in the month positions settle. Substantially all changes in values of commodity contracts are reported as operating revenues in our condensed consolidated statements of operations.
**14.**COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES
Strategic Use of Derivatives
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 13 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets and 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 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 our condensed consolidated statements of operations in operating revenues and fuel, purchased power costs and delivery fees.
Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in our condensed consolidated statements of operations in interest expense and related charges. During 2019, Vistra entered into $2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixed rate. The terms of these new swaps were matched against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms. The remaining existing swaps continue to hedge our exposure on $2.30 billion of debt through July 2026.
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 our condensed consolidated balance sheets at September 30, 2022 and December 31, 2021. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract. During the nine months ended September 30, 2022 and 2021, net losses of $780 million and $357 million, respectively, were recognized in operating revenues due to the discontinuance of NPNS accounting on retail electric contract portfolios in the third quarter of 2021 and second quarter of 2022 where physical settlement is no longer considered probable throughout the contract term. These amounts are reflected in commodity contracts derivative liabilities at September 30, 2022 and December 31, 2021.
| September 30, 2022 | |||||||||||||||||||||||||||||
| Derivative Assets | Derivative Liabilities | ||||||||||||||||||||||||||||
| Commodity Contracts | Interest Rate Swaps | Commodity Contracts | Interest Rate Swaps | Total | |||||||||||||||||||||||||
| Current assets | $ | 6,697 | $ | 80 | $ | 9 | $ | — | $ | 6,786 | |||||||||||||||||||
| Noncurrent assets | 966 | 73 | 23 | — | 1,062 | ||||||||||||||||||||||||
| Current liabilities | (33) | — | (8,723) | (40) | (8,796) | ||||||||||||||||||||||||
| Noncurrent liabilities | — | — | (1,753) | (50) | (1,803) | ||||||||||||||||||||||||
| Net assets (liabilities) | $ | 7,630 | $ | 153 | $ | (10,444) | $ | (90) | $ | (2,751) |
| December 31, 2021 | |||||||||||||||||||||||||||||
| Derivative Assets | Derivative Liabilities | ||||||||||||||||||||||||||||
| Commodity Contracts | Interest Rate Swaps | Commodity Contracts | Interest Rate Swaps | Total | |||||||||||||||||||||||||
| Current assets | $ | 2,496 | $ | 14 | $ | 3 | $ | — | $ | 2,513 | |||||||||||||||||||
| Noncurrent assets | 244 | 5 | 1 | — | 250 | ||||||||||||||||||||||||
| Current liabilities | — | — | (2,964) | (59) | (3,023) | ||||||||||||||||||||||||
| Noncurrent liabilities | (1) | — | (645) | (158) | (804) | ||||||||||||||||||||||||
| Net assets (liabilities) | $ | 2,739 | $ | 19 | $ | (3,605) | $ | (217) | $ | (1,064) |
At September 30, 2022 and December 31, 2021, there were no derivative positions accounted for as cash flow or fair value hedges.
The following table presents the pre-tax effect of derivative gains (losses) on net income, including realized and unrealized effects. Amount represents changes in fair value of 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, | |||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Commodity contracts (Operating revenues) | $ | (658) | $ | (919) | $ | (3,665) | $ | (1,017) | |||||||||||||||
| Commodity contracts (Fuel, purchased power costs and delivery fees) | 131 | 333 | 472 | 448 | |||||||||||||||||||
| Interest rate swaps (Interest expense and related charges) | 89 | (1) | 238 | 53 | |||||||||||||||||||
| Net loss | $ | (438) | $ | (587) | $ | (2,955) | $ | (516) |
Balance Sheet Presentation of Derivatives
We elect to report derivative assets and liabilities in our 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 our 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, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||||||||||||||||||||
| 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 | |||||||||||||||||||||||||||||||||||||||||||
| Derivative assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts | $ | 7,630 | $ | (6,726) | $ | (25) | $ | 879 | $ | 2,739 | $ | (2,051) | $ | (27) | $ | 661 | ||||||||||||||||||||||||||||||||||
| Interest rate swaps | 153 | (70) | — | 83 | 19 | (19) | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Total derivative assets | 7,783 | (6,796) | (25) | 962 | 2,758 | (2,070) | (27) | 661 | ||||||||||||||||||||||||||||||||||||||||||
| Derivative liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity contracts | (10,444) | 6,726 | 1,552 | (2,166) | (3,605) | 2,051 | 784 | (770) | ||||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | (90) | 70 | — | (20) | (217) | 19 | — | (198) | ||||||||||||||||||||||||||||||||||||||||||
| Total derivative liabilities | (10,534) | 6,796 | 1,552 | (2,186) | (3,822) | 2,070 | 784 | (968) | ||||||||||||||||||||||||||||||||||||||||||
| Net amounts | $ | (2,751) | $ | — | $ | 1,527 | $ | (1,224) | $ | (1,064) | $ | — | $ | 757 | $ | (307) |
(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 at September 30, 2022 and December 31, 2021:
| September 30, 2022 | December 31, 2021 | |||||||||||||||||||
| Derivative type | Notional Volume | Unit of Measure | ||||||||||||||||||
| Natural gas (a) | 6,577 | 4,701 | Million MMBtu | |||||||||||||||||
| Electricity | 743,035 | 440,236 | GWh | |||||||||||||||||
| Financial transmission rights (b) | 221,681 | 224,876 | GWh | |||||||||||||||||
| Coal | 50 | 25 | Million U.S. tons | |||||||||||||||||
| Fuel oil | 97 | 87 | Million gallons | |||||||||||||||||
| Emissions | 69 | 18 | Million tons | |||||||||||||||||
| Renewable energy certificates | 29 | 32 | Million certificates | |||||||||||||||||
| Interest rate swaps – variable/fixed (c) | $ | 6,720 | $ | 6,720 | Million U.S. dollars | |||||||||||||||
| Interest rate swaps – fixed/variable (c) | $ | 2,120 | $ | 2,120 | Million U.S. dollars |
(a)Represents gross notional forward sales, purchases and options transactions, 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 through July 2026.
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 require the posting of 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, 2022 | December 31, 2021 | ||||||||||
| Fair value of derivative contract liabilities (a) | $ | (2,658) | $ | (1,200) | |||||||
| Offsetting fair value under netting arrangements (b) | 1,532 | 660 | |||||||||
| Cash collateral and letters of credit | 377 | 95 | |||||||||
| Liquidity exposure | $ | (749) | $ | (445) |
____________
(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. At September 30, 2022, total credit risk exposure to all counterparties related to derivative contracts totaled $8.229 billion (including associated accounts receivable). The net exposure to those counterparties totaled $1.100 billion at September 30, 2022, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure totaling $168 million. At September 30, 2022, the credit risk exposure to the banking and financial sector represented 82% of the total credit risk exposure and 24% of the net exposure.
Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.
We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
**15.**RELATED PARTY TRANSACTIONS
In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.
Registration Rights Agreement
Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the RRA) with certain selling stockholders. Pursuant to the RRA, we maintain a registration statement on Form S-3 providing for registration of the resale of the Vistra common stock held by such selling stockholders. In addition, under the terms of the RRA, among other things, if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the RRA the opportunity to register all or part of their shares on the terms and conditions set forth in the RRA.
Tax Receivable Agreement
On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH. See Note 7 for discussion of the TRA.
**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, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 states in the U.S.
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, respectively, 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 and Oakland power plant sites (see Note 2).
The Sunset segment consists of generation plants with announced retirement dates after December 31, 2022. 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, 2022.
The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 3). The Asset Closure segment also includes results from generation plants we plan to retire in the year ended December 31, 2022. 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. We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants scheduled to be retired in 2022.
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 2021 Form 10-K. Our CODM uses more than one measure to assess segment performance, but primarily focuses on Adjusted EBITDA. While we believe this is a useful metric in evaluating operating performance, it is not a metric defined by U.S. GAAP and may not be comparable to non-GAAP metrics presented by other companies. Adjusted EBITDA is most comparable to consolidated net income (loss) prepared based on U.S. GAAP. 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 (c) | Eliminations | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues (a): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | 3,258 | $ | 3,627 | $ | 1,126 | $ | 236 | $ | 280 | $ | 68 | $ | 1 | $ | (3,450) | $ | 5,146 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | 2,160 | 843 | 508 | 90 | (62) | (60) | — | (488) | 2,991 | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization (b): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | (36) | $ | (135) | $ | (187) | $ | 4 | $ | (19) | $ | 1 | $ | (18) | $ | — | $ | (390) | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | (53) | (179) | (164) | (15) | (27) | (13) | (17) | — | (468) | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | (1,220) | $ | 2,147 | $ | (120) | $ | 70 | $ | 36 | $ | 6 | $ | (25) | $ | — | $ | 894 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | 782 | (4) | (228) | (19) | (248) | (138) | (26) | — | 119 | |||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) (c): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | (1,227) | $ | 2,156 | $ | (119) | $ | 72 | $ | 36 | $ | 11 | $ | (251) | $ | — | $ | 678 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | 779 | 4 | (233) | (18) | (248) | (133) | (141) | — | 10 | |||||||||||||||||||||||||||||||||||||||||||||||
| Nine Months ended | Retail | Texas | East | West | Sunset | Asset Closure | Corporate and Other (c) | Eliminations | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues (a): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | 6,876 | $ | 1,909 | $ | 2,400 | $ | 387 | $ | 56 | $ | 296 | $ | 1 | $ | (2,066) | $ | 9,859 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | 5,829 | 1,458 | 1,738 | 171 | 188 | (79) | — | (542) | 8,763 | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization (b): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | (109) | $ | (404) | $ | (545) | $ | (26) | $ | (56) | $ | (22) | $ | (52) | $ | — | $ | (1,214) | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | (160) | (462) | (553) | (30) | (78) | (21) | (51) | — | (1,355) | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | 2,121 | $ | (1,538) | $ | (908) | $ | 33 | $ | (582) | $ | (107) | $ | (98) | $ | — | $ | (1,079) | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | 2,689 | (3,726) | (321) | (71) | (492) | (398) | (82) | — | (2,401) | |||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) (c): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | 2,099 | $ | (1,455) | $ | (910) | $ | 36 | $ | (583) | $ | (96) | $ | (53) | $ | — | $ | (962) | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | 2,677 | (3,651) | (332) | (62) | (488) | (373) | 235 | — | (1,994) | |||||||||||||||||||||||||||||||||||||||||||||||
| Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | — | $ | 320 | $ | 33 | $ | 74 | $ | 26 | $ | — | $ | 37 | $ | — | $ | 490 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | 1 | 214 | 39 | 7 | 25 | 4 | 62 | — | 352 |
(a)The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:
| Three months ended | Retail (1) | Texas | East | West | Sunset | Asset Closure | Corporate and Other | Eliminations (2) | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | 225 | $ | 1,485 | $ | (103) | $ | 56 | $ | 49 | $ | 62 | $ | — | $ | (1,428) | $ | 346 | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | (383) | (697) | (303) | (46) | (395) | (154) | — | 1,117 | $ | (861) | ||||||||||||||||||||||||||||||||||||||||||||||
| Nine Months ended | Retail (1) | Texas | East | West | Sunset | Asset Closure | Corporate and Other | Eliminations (2) | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||
| September 30, 2022 | $ | (812) | $ | (2,139) | $ | (951) | $ | (23) | $ | (677) | $ | 92 | $ | — | $ | 2,409 | $ | (2,101) | ||||||||||||||||||||||||||||||||||||||
| September 30, 2021 | (406) | (2,354) | (486) | (135) | (724) | (285) | — | 3,244 | $ | (1,146) |
(1)Retail segment includes unrealized net gains of $217 million and unrealized net losses of $357 million for the three months ended September 30, 2022 and 2021, respectively, and unrealized net losses of $780 million and $357 million for the nine months ended September 30, 2022 and 2021, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios in the third quarter of 2021 and second quarter of 2022 where physical settlement is no longer considered probable throughout the contract term.
(2)Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
(b)See Note 1 for information related to an immaterial out-of-period adjustment recorded in the third quarter of 2021 to correct depreciation expense and accumulated depreciation related to prior periods. Substantially all of the understated depreciation expense for the years ended December 31, 2018, 2019 and 2020 relates to the Texas segment, and the overstated depreciation expense for the six month period ended June 30, 2021 relates entirely to the East segment.
(c)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 second quarter of 2021, we recognized an impairment loss of $38 million related to our Zimmer generation facility in Ohio as a result of a significant decrease in the estimated useful life of the facility, reflecting a decrease in the economic forecast of the facility and the inability to secure capacity revenues for the plant in the PJM capacity auction held in May 2021. The impairment is reported in our Asset Closure segment and includes write-downs of property, plant and equipment of $33 million and write-downs of inventory of $5 million.
Interest Expense and Related Charges
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Interest paid/accrued | $ | 156 | $ | 124 | $ | 429 | $ | 354 | |||||||||||||||
| Unrealized mark-to-market net gains on interest rate swaps | (90) | (13) | (261) | (92) | |||||||||||||||||||
| Amortization of debt issuance costs, discounts and premiums | 7 | 9 | 20 | 23 | |||||||||||||||||||
| Debt extinguishment (gain) loss | (1) | — | (1) | 1 | |||||||||||||||||||
| Capitalized interest | (8) | (4) | (22) | (22) | |||||||||||||||||||
| Other | 7 | 8 | 21 | 24 | |||||||||||||||||||
| Total interest expense and related charges | $ | 71 | $ | 124 | $ | 186 | $ | 288 |
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 4.18% and 3.89% at September 30, 2022 and 2021.
Other Income and Deductions
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Other income: | |||||||||||||||||||||||
| Insurance settlements (a) | $ | — | $ | 9 | $ | 63 | $ | 74 | |||||||||||||||
| Gain on settlement of rail transportation disputes (b) | — | — | — | 15 | |||||||||||||||||||
| Sale of land (b) | 3 | 1 | 8 | 2 | |||||||||||||||||||
| Interest income | 2 | — | 4 | — | |||||||||||||||||||
| All other | 5 | 6 | 13 | 17 | |||||||||||||||||||
| Total other income | $ | 10 | $ | 16 | $ | 88 | $ | 108 | |||||||||||||||
| Other deductions: | |||||||||||||||||||||||
| All other | 5 | 5 | 18 | 13 | |||||||||||||||||||
| Total other deductions | $ | 5 | $ | 5 | $ | 18 | $ | 13 |
(a)For the nine months ended September 30, 2022, $62 million reported in the Texas segment and $1 million reported in the Corporate and Other non-segment. For the three months ended September 30, 2021, $5 million reported in the Sunset segment and $4 million reported in the Texas segment. For the nine months ended September 30, 2021, $67 million reported in the Texas segment, $5 million reported in the Sunset Segment and $2 million reported in the Corporate and Other non-segment.
(b)Reported in the Asset Closure segment.
Restricted Cash
| September 30, 2022 | December 31, 2021 | ||||||||||||||||||||||
| Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | ||||||||||||||||||||
| Amounts related to remediation escrow accounts | $ | 23 | $ | 10 | $ | 21 | $ | 13 | |||||||||||||||
| Total restricted cash | $ | 23 | $ | 10 | $ | 21 | $ | 13 |
Trade Accounts Receivable
| September 30, 2022 | December 31, 2021 | ||||||||||
| Wholesale and retail trade accounts receivable | $ | 1,945 | $ | 1,442 | |||||||
| Allowance for uncollectible accounts | (91) | (45) | |||||||||
| Trade accounts receivable — net | $ | 1,854 | $ | 1,397 |
Gross trade accounts receivable at September 30, 2022 and December 31, 2021 included unbilled retail revenues of $587 million and $426 million, respectively.
Allowance for Uncollectible Accounts Receivable
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2022 | 2021 | ||||||||||||||||||||||
| Allowance for uncollectible accounts receivable at beginning of period | $ | 45 | $ | 45 | |||||||||||||||||||
| Increase for bad debt expense | 136 | 86 | |||||||||||||||||||||
| Decrease for account write-offs | (90) | (72) | |||||||||||||||||||||
| Allowance for uncollectible accounts receivable at end of period | $ | 91 | $ | 59 |
Inventories by Major Category
| September 30, 2022 | December 31, 2021 | ||||||||||
| Materials and supplies | $ | 272 | $ | 260 | |||||||
| Fuel stock | 258 | 314 | |||||||||
| Natural gas in storage | 60 | 36 | |||||||||
| Total inventories | $ | 590 | $ | 610 |
Investments
| September 30, 2022 | December 31, 2021 | ||||||||||
| Nuclear plant decommissioning trust | $ | 1,547 | $ | 1,960 | |||||||
| Assets related to employee benefit plans | 40 | 42 | |||||||||
| Land | 41 | 44 | |||||||||
| Miscellaneous other | 9 | 3 | |||||||||
| Total investments | $ | 1,637 | $ | 2,049 |
Nuclear Decommissioning Trust
Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs 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 trust fund. Income and expense, including gains and losses associated with the trust fund assets and the decommissioning liability are offset by a corresponding change in a regulatory asset/liability (currently a regulatory asset reported in other noncurrent assets) that will ultimately be settled through changes in Oncor's delivery fees rates. If funds recovered from Oncor's customers held in the trust fund are determined to be inadequate to decommission the Comanche Peak nuclear generation plant, Oncor would be required to collect all additional amounts from its customers, with no obligation from Vistra, provided that Vistra complied with PUCT rules and regulations regarding decommissioning trusts. A summary of the fair market value of investments in the fund follows:
| September 30, 2022 | December 31, 2021 | ||||||||||
| Debt securities (a) | $ | 592 | $ | 679 | |||||||
| Equity securities (b) | 955 | 1,281 | |||||||||
| Total | $ | 1,547 | $ | 1,960 |
(a)The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate 2.71% and 2.54% at September 30, 2022 and December 31, 2021, respectively, and an average maturity of 11 years and 10 years at September 30, 2022 and December 31, 2021, respectively.
(b)The investment objective for 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.
Debt securities held at September 30, 2022 mature as follows: $208 million in one to five years, $151 million in five to 10 years and $233 million after 10 years.
The following table summarizes proceeds from sales of securities and investments in new securities.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Proceeds from sales of securities | $ | 94 | $ | 99 | $ | 428 | $ | 366 | |||||||||||||||
| Investments in securities | $ | (101) | $ | (105) | $ | (446) | $ | (382) |
Property, Plant and Equipment
| September 30, 2022 | December 31, 2021 | ||||||||||
| Power generation and structures | $ | 16,734 | $ | 16,195 | |||||||
| Land | 587 | 608 | |||||||||
| Office and other equipment | 191 | 183 | |||||||||
| Total | 17,512 | 16,986 | |||||||||
| Less accumulated depreciation | (5,683) | (4,801) | |||||||||
| Net of accumulated depreciation | 11,829 | 12,185 | |||||||||
| Finance lease right-of-use assets (net of accumulated depreciation) | 173 | 173 | |||||||||
| Nuclear fuel (net of accumulated amortization of $129 million and $125 million) | 284 | 212 | |||||||||
| Construction work in progress | 264 | 486 | |||||||||
| Property, plant and equipment — net | $ | 12,550 | $ | 13,056 |
Depreciation expenses totaled $338 million and $398 million for three months ended September 30, 2022 and 2021, respectively, and $1.057 billion and $1.147 billion for nine months ended September 30, 2022 and 2021, respectively. See Note 1 for information related to an out-of-period adjustment due to an immaterial correction of prior periods.
Asset Retirement and Mining Reclamation Obligations (ARO)
These liabilities 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. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor. As of September 30, 2022 and December 31, 2021, asbestos removal liabilities totaled zero and $3 million, respectively. We have also identified conditional AROs for asbestos removal and disposal, which are specific to certain generation assets.
At September 30, 2022, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.674 billion, which is higher than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory asset has been recorded to our condensed consolidated balance sheet of $127 million in other noncurrent assets.
The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our condensed consolidated balance sheets, for the nine months ended September 30, 2022 and 2021.
| Nine Months Ended September 30, 2022 | Nine Months Ended September 30, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||
| Nuclear Plant Decom- missioning | Mining Land Reclamation | Coal Ash and Other | Total | Nuclear Plant Decom- missioning | Mining Land Reclamation | Coal Ash and Other | Total | ||||||||||||||||||||||||||||||||||||||||
| Liability at beginning of period | $ | 1,635 | $ | 320 | $ | 495 | $ | 2,450 | $ | 1,585 | $ | 359 | $ | 492 | $ | 2,436 | |||||||||||||||||||||||||||||||
| Additions: | |||||||||||||||||||||||||||||||||||||||||||||||
| Accretion | 39 | 11 | 15 | 65 | 38 | 12 | 15 | 65 | |||||||||||||||||||||||||||||||||||||||
| Adjustment for change in estimates | — | (11) | 23 | 12 | — | (16) | 10 | (6) | |||||||||||||||||||||||||||||||||||||||
| Reductions: | |||||||||||||||||||||||||||||||||||||||||||||||
| Payments | — | (54) | (12) | (66) | — | (48) | (11) | (59) | |||||||||||||||||||||||||||||||||||||||
| Liability at end of period | 1,674 | 266 | 521 | 2,461 | 1,623 | 307 | 506 | 2,436 | |||||||||||||||||||||||||||||||||||||||
| Less amounts due currently | — | (95) | (26) | (121) | — | (88) | (22) | (110) | |||||||||||||||||||||||||||||||||||||||
| Noncurrent liability at end of period | $ | 1,674 | $ | 171 | $ | 495 | $ | 2,340 | 1,623 | 219 | 484 | 2,326 |
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
| September 30, 2022 | December 31, 2021 | ||||||||||
| Retirement and other employee benefits | $ | 268 | $ | 276 | |||||||
| Winter Storm Uri impact (a) | 169 | 261 | |||||||||
| Identifiable intangible liabilities (Note 5) | 142 | 147 | |||||||||
| Regulatory liability (b) | — | 325 | |||||||||
| Finance lease liabilities | 238 | 235 | |||||||||
| Uncertain tax positions, including accrued interest | 14 | 13 | |||||||||
| Liability for third-party remediation | 16 | 17 | |||||||||
| Accrued severance costs | 36 | 39 | |||||||||
| Other accrued expenses | 234 | 176 | |||||||||
| Total other noncurrent liabilities and deferred credits | $ | 1,117 | $ | 1,489 |
(a)Includes the allocation of ERCOT default uplift charges and future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.
(b)As of September 30, 2022, the carrying value of our ARO related to our nuclear generation plant decommissioning was higher than the fair value of the assets contained in the nuclear decommissioning trust and recorded as a regulatory asset of $127 million in other noncurrent assets. As of December 31, 2021, the fair value of the assets contained in the nuclear decommissioning trust was higher than the carrying value of our ARO related to our nuclear generation plant decommissioning and recorded as a regulatory liability of $325 million in other noncurrent liabilities and deferred credits.
Fair Value of Debt
| September 30, 2022 | December 31, 2021 | |||||||||||||||||||||||||||||||
| Long-term debt (see Note 10): | Fair Value Hierarchy | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||||||||
| Long-term debt under the Vistra Operations Credit Facilities | Level 2 | $ | 2,526 | $ | 2,433 | $ | 2,549 | $ | 2,518 | |||||||||||||||||||||||
| Vistra Operations Senior Notes | Level 2 | 9,373 | 8,629 | 7,880 | 8,193 | |||||||||||||||||||||||||||
| Forward Capacity Agreements | Level 3 | — | — | 211 | 211 | |||||||||||||||||||||||||||
| Equipment Financing Agreements | Level 3 | 86 | 81 | 85 | 85 | |||||||||||||||||||||||||||
| Building Financing | Level 2 | — | — | 3 | 3 | |||||||||||||||||||||||||||
| Other debt | Level 3 | — | — | 3 | 3 |
We determine fair value in accordance with accounting standards as discussed in Note 13. 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 our condensed consolidated statements of cash flows to the amounts reported in our condensed consolidated balance sheets at September 30, 2022 and December 31, 2021:
| September 30, 2022 | December 31, 2021 | ||||||||||
| Cash and cash equivalents | $ | 535 | $ | 1,325 | |||||||
| Restricted cash included in current assets | 23 | 21 | |||||||||
| Restricted cash included in noncurrent assets | 10 | 13 | |||||||||
| Total cash, cash equivalents and restricted cash | $ | 568 | $ | 1,359 |
The following table summarizes our supplemental cash flow information for the nine months ended September 30, 2022 and 2021:
| Nine Months Ended September 30, | |||||||||||
| 2022 | 2021 | ||||||||||
| Cash payments related to: | |||||||||||
| Interest paid | $ | 468 | $ | 425 | |||||||
| Capitalized interest | (22) | (22) | |||||||||
| Interest paid (net of capitalized interest) | $ | 446 | $ | 403 | |||||||
| Income taxes paid, net (a) | $ | 19 | $ | 44 | |||||||
(a)For the nine months ended September 30, 2022 and 2021, we paid state income taxes of $27 million and $46 million, respectively, and received state tax refunds of $8 million and $2 million, respectively.
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