What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2024-02-29 compared with 2023-03-01 · 593 added, 559 removed, 1720 unchanged (40% of the section changed)

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We have audited the accompanying consolidated balance sheets of Vistra Corp.

and its subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, consolidated statements of comprehensive income (loss), consolidated statements of cash flows, and consolidated statement of changes in equity, for each of the three years in the period ended December 31, 2022, and the related notes and the schedule listed in the Index at Item 15(b) (collectively referred to as the “financial statements”).

and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, consolidated statements of comprehensive income (loss), consolidated statements of cash flows, and consolidated statement of changes in equity, for each of the three years in the period ended December 31, 2023, and the related notes and the schedule listed in the Index at Item 15(b) (collectively referred to as the “financial statements”).

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2023, expressed an unqualified opinion on the Company’s internal control over financial reporting.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

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We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Tax Receivable Agreement Obligation — Refer to Notes 1 and 7 to the financial statements

Critical Audit Matter Description

The Company has a tax receivable agreement (TRA) obligation that requires the Company to make annual payments to the TRA rights holders based on cash savings in income tax resulting from a step up in the tax basis of certain assets upon emergence from bankruptcy in 2016.

The carrying value of the TRA obligation is based on the discounted amount of forecasted payments to the TRA rights holders.

Determining the carrying value of the TRA obligation requires management to make significant estimates and assumptions in preparing its forecast of taxable income for a period of approximately 35 years.

Changes to either the estimated timing or amount of expected TRA payments impact the carrying value of the obligation.

As of December 31, 2022, the carrying value of the TRA obligation totaled $522 million.

Given the significant judgements made by management to estimate the TRA obligation, performing audit procedures to evaluate the reasonableness of management’s estimate and assumptions related to the estimated future taxable income required a high degree of auditor judgement and an increased extent of effort, including the need to involve our income tax specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the evaluation of estimated future taxable income included the following, among others:

• We tested the effectiveness of controls over management’s determination of the TRA obligation carrying amount, including controls over developing estimated future taxable income.

• With the assistance of our income tax specialists, we evaluated the following elements in testing management’s estimated future taxable income:

◦ The application of tax laws and regulations

◦ Future reversals of existing temporary differences, including the timing and amount of loss carryforwards

• We evaluated the reasonableness of management’s estimates of future taxable income by comparing the estimates to:

◦ Historical taxable income

◦ Internal communications to management and the Board of Directors

◦ Forecasted information included in the Company's press releases as well as in analyst and industry reports for the Company

• We assessed the consistency of future taxable income with evidence obtained in other areas of the audit.

Fair Value Measurements — Level 3 Derivative Assets and Liabilities — Refer to Notes 1 and 14 to the financial statements

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Fair Value Measurements — Certain Complex Level 3 Derivative Assets and Liabilities — Refer to Notes 1 and 16 to the financial statements

Critical Audit Matter Description

The Company has assets and liabilities whose fair values are based on complex proprietary models and/or unobservable inputs.

These financial instruments can span a broad array of product types and generally include (1) power purchases and sales that include power and heat rate positions;

(2) physical power and natural gas options, spread options, and swaptions;

(3) forward purchase contracts for power, natural gas, coal, environmental allowances, congestion revenue rights and financial transmission rights;

The Company has derivative assets and liabilities whose fair values are based on complex proprietary models and/or unobservable inputs.

These financial instruments can span a broad array of contract types, some of which include especially complex valuations due to unique contract terms and significant judgement by management in estimating prices or volumes, including (1) power purchases and sales that include power and heat rate positions;

(2) physical power and natural gas options and swaptions;

(3) forward purchase contracts for congestion revenue rights;

and (4) retail sales contracts.

Under accounting principles generally accepted in the United States of America, these financial instruments are generally classified as Level 3 derivative assets or liabilities.

As of December 31, 2022, the fair value of the Level 3 derivative assets and liabilities totaled $791 million and $2,010 million, respectively.

Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of Level 3 derivative assets and liabilities, performing audit procedures to evaluate the reasonableness of the fair value of Level 3 derivative assets and liabilities required a high degree of auditor judgment and an increased extent of effort, including the need to involve our energy commodity fair value specialists who possess significant quantitative and modeling expertise.

Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of the aforementioned Level 3 derivative assets and liabilities, performing audit procedures to evaluate the reasonableness of the fair value of Level 3 derivative assets and liabilities required a high degree of auditor judgment and an increased extent of effort, including the need to involve our energy commodity fair value specialists who possess significant quantitative and modeling expertise.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the evaluation of the fair value of Level 3 derivative assets and liabilities included the following, among others:

• We tested the effectiveness of controls over derivative asset and liability valuations, including controls related to verification of illiquid price curves and other significant unobservable valuation inputs.

• We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2022, to confirm our understanding of the types of instruments outstanding.

• We tested the effectiveness of controls over derivative asset and liability valuations, including controls related to appropriate application of illiquid price curves and other significant unobservable valuation inputs.

• We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2023, to obtain an understanding of the types of instruments outstanding.

• We assessed the consistency by which management has applied illiquid price curves and significant unobservable valuation inputs.

• With the assistance of our energy commodity fair value specialists, we developed independent estimates of the fair value of a sample of Level 3 derivative instruments and compared our estimates to the Company's estimates.

Valuation Allowance for Deferred Tax Assets — Refer to Notes 1 and 6 to the financial statements

Critical Audit Matter Description

As described in Note 6 to the consolidated financial statements, as of December 31, 2022, the Company has net deferred tax assets of $1.709 million.

The Company evaluates the realizability of the deferred tax assets, and to the extent that the Company estimates that it is more likely than not that a benefit will not be realized, a valuation allowance is recognized to reduce the deferred tax assets to an amount that is more likely than not to be realized.

As a part of this evaluation, the Company assesses all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies, and results of recent operations, to determine whether sufficient future taxable income will be generated to realize existing deferred tax assets.

The Company has identified objective and verifiable negative evidence, most notably, in the form of cumulative losses on an unadjusted basis over the preceding 12 quarters ended December 31, 2022.

When determining whether cumulative losses in recent years exist, an entity should generally not exclude nonrecurring items from its results.

It may, however, be appropriate for the entity to exclude nonrecurring items when projecting future income in connection with its determination of the amount of the valuation allowance needed.

The Company evaluated its historical earnings after adjusting for certain nonrecurring items for purposes of projecting future income, performed scheduling of the reversal of temporary differences, and considered other evidence giving rise to positive and negative evidence.

On the basis of this evaluation, the Company considered the relative weight of the available negative and positive evidence and concluded its net deferred tax assets of $1,709 million, inclusive of a $63 million valuation allowance, will be realizable.

We identified the valuation of net deferred tax assets as a critical audit matter because of the significant judgments made by management in projecting future income.

Our audit procedures required a high degree of auditor judgment and an increased extent of effort, including the need to involve our tax specialists, to evaluate the reasonableness of management's estimates of the projected future income.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the determination that it is more likely than not that sufficient taxable income will be generated in the future to realize deferred tax assets included the following, among others:

• We tested the effectiveness of management’s controls over deferred tax assets, estimates of projected income, and the evaluation of whether it is more likely than not that the deferred tax assets will be realized

• With the assistance of our tax specialists, we evaluated:

◦ the Company’s adjusted book income calculation, including the accuracy the 3-year cumulative income/loss position as adjusted for nonrecurring items

◦ the reasonableness of the methods, assumptions, and judgments used by management, including the evaluation of the relative weight of the positive and negative evidence available in management's assessment to determine whether a valuation allowance was necessary

◦ the future reversals of taxable temporary differences and whether the sources of management’s income were of the appropriate character and sufficient to utilize the deferred tax assets under the relevant tax law, considering attribute expiry

◦ the completeness and accuracy of the deferred tax assets included in the Company’s scheduling exercise to ensure all attributes were appropriately included

◦ any tax law changes that would impact the Company’s ability to utilize deferred tax assets and evaluated whether the Company’s analysis appropriately factors in the law changes

• We evaluated management’s ability to accurately estimate income by comparing actual results to management’s historical estimates and evaluating whether there have been any changes that would affect management’s ability to continue to accurately estimate income.

• We assessed the consistency of projected income with evidence obtained in other areas of the audit.

/s/ Deloitte & Touche LLP

Dallas, Texas

March 1, 2023

February 28, 2024

We have served as the Company's auditor since 2002.

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Impacts of Tax Receivable Agreement (Note 8) ( 164 ) ( 128 ) 53

Equity in earnings of unconsolidated investment (Note 20) — — 4

Net income (loss) before income taxes 2,000 ( 1,560 ) ( 1,722 )

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Other comprehensive income (loss), net of tax effects:

Effects related to pension and other retirement benefit obligations (net of tax expense (benefit) of $ 7 , $ 9 and $( 5 ))

Effects related to pension and other retirement benefit obligations (net of tax expense of $ — , $ 7 and $ 9 )

Total other comprehensive income (loss) ( 1 ) 23 32

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Deferred income tax expense (benefit), net 457 ( 359 ) ( 475 )

Gain on sale of land ( 95 ) ( 8 ) ( 9 )

Impairment of long-lived and other assets 49 74 71

Loss on disposal of investment in NELP — — 29

Unrealized net (gain) loss from mark-to-market valuations of commodities ( 490 ) 2,510 759

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Impacts of Tax Receivable Agreement 164 128 ( 53 )

Gain on TRA settlement ( 29 ) — —

Bad debt expense 164 179 110

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Accrued employee incentive 58 21 ( 68 )

Tax Receivable Agreement payment ( 1 ) ( 2 ) —

Asset retirement obligation settlement ( 81 ) ( 87 ) ( 88 )

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Insurance proceeds 15 39 89

Proceeds from sale of assets 21 30 24

Proceeds from sale of nuclear fuel 57 — —

Proceeds from sales of property, plant and equipment 115 78 30

Other, net ( 5 ) ( 4 ) ( 4 )

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Proceeds from forward capacity agreement — — 500

Net borrowings/(payments) under accounts receivable financing 425 ( 300 ) ( 150 )

Net borrowings/(repayments) under accounts receivable financing ( 425 ) 425 ( 300 )

Borrowings under Revolving Credit Facility 100 1,750 1,450

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Debt issuance costs ( 59 ) ( 31 ) ( 13 )

Share repurchases ( 1,949 ) ( 471 ) —

Stock repurchases ( 1,245 ) ( 1,949 ) ( 471 )

Dividends paid to common stockholders ( 313 ) ( 302 ) ( 290 )

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Margin deposits related to commodity contracts 1,244 3,137

Uplift securitization proceeds receivable from ERCOT (Note 1) — 544

Margin deposits posted under affiliate financing agreement (Note 11) 439 —

Prepaid expense and other current assets 364 293

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Total current liabilities 9,823 10,337

Margin deposits financing with affiliate (Note 11) 439 —

Long-term debt, less amounts due currently (Note 12) 12,116 11,933

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Asset retirement obligations (Note 22) 2,414 2,309

Other noncurrent liabilities and deferred credits (Note 20) 1,004 1,489

Total liabilities 27,869 21,391

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

Other noncurrent liabilities and deferred credits (Note 22) 951 1,004

Total liabilities 27,644 27,869

Commitments and Contingencies (Note 14)

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December 31, 2023 and 2022 — 1,000,000 ;

Series C (liquidation preference — $ 1,000 ;

shares outstanding:

December 31, 2023 — 476,081 ;

December 31, 2022 — zero )

Common stock (par value — $ 0.01 ;

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Retained deficit ( 2,613 ) ( 3,643 )

Accumulated other comprehensive income (loss) 7 ( 16 )

Accumulated other comprehensive income 6 7

Stockholders' equity 5,307 4,902

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$ — $ 5 $ ( 973 ) $ 9,786 $ ( 399 ) $ ( 48 ) $ 8,371 $ ( 10 ) $ 8,361

Series A Preferred Stock issued 1,000 — — ( 10 ) — — 990 — 990

Series B Preferred Stock issued 1,000 — — ( 15 ) — — 985 — 985

Stock repurchases — — ( 585 ) — — — ( 585 ) — ( 585 )

Effects of stock-based compensation — — — 60 — — 60 — 60

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Dividends declared on common stock — — — — ( 290 ) — ( 290 ) — ( 290 )

Adoption of accounting standard — — — — ( 4 ) — ( 4 ) — ( 4 )

Change in accumulated other comprehensive income (loss) — — — — — 32 32 — 32

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$ 2,000 $ 5 $ ( 1,558 ) $ 9,824 $ ( 1,964 ) $ ( 16 ) $ 8,291 $ 1 $ 8,292

Series A Preferred Stock issued 1,000 — — ( 10 ) — — 990 — 990

Series B Preferred Stock issued 1,000 — — ( 15 ) — — 985 — 985

Stock repurchases — — ( 1,837 ) — — — ( 1,837 ) — ( 1,837 )

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Dividends declared on common stock — — — — ( 302 ) — ( 302 ) — ( 302 )

Dividends declared on preferred stock — — — — ( 151 ) — ( 151 ) — ( 151 )

Change in accumulated other comprehensive income (loss) — — — — — 23 23 — 23

Investment by noncontrolling interest — — — — — — — 1 1

Other — — — 1 1 — 2 ( 2 ) —

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$ 2,000 $ 5 $ ( 3,395 ) $ 9,928 $ ( 3,643 ) $ 7 $ 4,902 $ 16 $ 4,918

Series C Preferred Stock issued 476 — — — — — 476 — 476

Stock repurchases ( 1,267 ) ( 1,267 ) ( 1,267 )

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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.

See Glossary of Terms and Abbreviations for defined terms.

Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S.

Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.

Effective July 2, 2020, we changed our name from Vistra Energy Corp.

to Vistra Corp.

(Vistra) to distinguish from companies that are involved in the exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect or integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business leading the clean power transition through our Vistra Zero portfolio while powering the communities we serve with safe, reliable and affordable power.

Vistra has six reportable segments:

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See Note 21 for further information concerning our reportable business segments.

Transaction Agreement

On March 6, 2023, Vistra Operations and Merger Sub entered into a transaction agreement (Transaction Agreement) with Energy Harbor pursuant to which, upon the terms and subject to the conditions thereof, Merger Sub will be merged with and into Energy Harbor, with Energy Harbor surviving as an indirect subsidiary of Vistra (Merger, and collectively with the other transactions contemplated by the Transaction Agreement, the Transactions).

The Transaction Agreement, the Merger and the other Transactions were approved by each of Vistra's board of directors (Board) and Energy Harbor's board of directors.

On February 16, 2024, we received approval from FERC to acquire Energy Harbor.

FERC's approval was the last regulatory approval needed, and we anticipate closing on March 1, 2024.

See Note 2 for more information concerning the Transaction Agreement.

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.

This severe weather resulted in surging demand for power, natural 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.

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.

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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 (see Note 12).

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 February 2023, the Board declared a quarterly dividend of $ 0.1975 per share of common stock that will be paid in March 2023.

In February 2023, the Board declared a semi-annual dividend of $ 40.00 per share of Series A Preferred Stock that will be paid in April 2023.

See Note 8 for information on the 2024 TRA Rights repurchases and tender offer, Note 12 for information on the January 2024 Senior Secured Notes Tender Offer and Note 15 for information on the February 2024 declaration of common and preferred stock dividends and the additional $ 1.5 billion authorization under the Share Repurchase Program.

Significant Accounting Policies

Basis of Presentation

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dollars unless otherwise indicated.

Certain prior period amounts have been reclassified to conform with the current year presentation.

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities 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.

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities as of the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgments related to the potential timing of events and other estimates.

In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities utilizing instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks.

We enter into contracts for the purchase and sale of electricity, natural gas, coal and other commodities utilizing instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks.

If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses.

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Electricity hedges, financial natural gas hedges and trading activities are primarily reported as revenue.

Physical or financial hedges for coal, diesel or uranium, along with physical natural gas trades, are primarily reported as fuel expense.

Physical or financial hedges for coal or fuel oil, along with physical natural gas trades, are primarily reported as fuel expense.

Realized and unrealized gains and losses associated with interest rate swap transactions are reported in the consolidated statements of operations in interest expense.

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See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts.

Advertising Expense

We expense advertising costs as incurred and include them within SG&A expenses.

Advertising expenses totaled $ 47 million, $ 48 million and $ 43 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Impairment of Long-Lived Assets

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Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable.

See Note 20 for details of impairments of long-lived assets recorded in 2022, 2021 and 2020.

See Note 22 for details of impairments of long-lived assets recorded.

Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects.

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Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation.

The fair value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model.

Forfeitures are recognized as they occur.

We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award.

Forfeitures are recognized as they occur.

See Note 19 for additional information regarding stock-based compensation.

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We report franchise and revenue-based taxes in SG&A expense in our consolidated statements of operations.

Investment tax credits are accounted for under the deferral method, which resulted in a reduction to the basis of our solar and battery storage facilities of $ 54 million, zero and zero and a corresponding increase in the deferred tax assets in 2022, 2021 and 2020, respectively.

Investment tax credits which are not transferable or refundable under the IRA are accounted for using the deferral method, which reduces the basis of our solar and battery storage facilities.

As of both December 31, 2023 and 2022, deferred tax assets related to these credits totaled $ 70 million.

Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as required under accounting rules.

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Cash and Cash Equivalents

For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered cash equivalents.

For purposes of reporting cash and cash equivalents, temporary cash investments purchased with an original maturity of three months or less are considered cash equivalents.

Restricted Cash

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Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available.

Changes in estimates related to assets that have been retired or for which capitalized costs are not recoverable are recorded as operating costs in the consolidated statements of operations.

Changes in estimates related to assets that have been retired or for which costs are not recoverable are recorded as operating costs in the consolidated statements of operations.

Regulatory Asset or Liability

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See Note 22 for discussion of these and other investments.

Noncontrolling Interest

Noncontrolling interest is comprised of the 20 % of Electric Energy, Inc.

(EEI) that we do not own.

EEI is our consolidated subsidiary that owns a coal facility in Joppa, Illinois that was retired September 1, 2022 (see Note 3).

This noncontrolling interest is classified as a component of equity separate from stockholders' equity in the consolidated balance sheets.

Treasury Stock

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Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option.

We apply the practical expedient permitted by ASC 842 to not separate lease and non-lease components for a majority of our lease asset classes.

We apply the practical expedient permitted by ASC 842, Leases to not separate lease and non-lease components for a majority of our lease asset classes.

Leases with an initial lease term of 12 months or less are not recorded on the balance sheet;

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We also present lessor sublease income on a net basis against the related lessee lease expense.

Adoption of Accounting Standards Issued in 2023

Improvements to Reportable Segment Disclosures — In November 2023, the Financial Accounting Standards Board (FASB) issued ASU No.

2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures , to improve the disclosures about reportable segments and add more detailed information about a reportable segment's expenses.

The amendments in the ASU require public entities to disclose on an annual and interim basis significant segment expenses that are regularly provided to the chief operating decision maker (CODM) and included within each reported measure of segment profit or loss, other segment items by reportable segment, the title and position of the CODM, and an explanation of how the CODM uses the reported measures of segment profit or loss in assessing segment performance and deciding how to allocate resources.

The ASU does not change the definition of a segment, the method for determining segments, the criteria for aggregating operating segments into reportable segments, or the current specifically enumerated segment expenses that are required to be disclosed.

The Company will adopt the amendments in this ASU for its fiscal year ended December 31, 2024 and interim periods within its fiscal year ended December 31, 2025.

The amendment will be applied retrospectively to all prior periods presented.

We are currently evaluating the impact this ASU will have on our consolidated financial statements and related disclosures.

Improvements to Income Tax Disclosures — In December 2023, the FASB issued ASU No.

2023-09 (ASU 2023-09), Income Taxes (Topic 740):

Improvements to Income Tax Disclosures to enhance the transparency and decision usefulness of income tax disclosures.

ASU 2023-09 is effective for annual periods beginning after December 15, 2024 on a prospective basis.

Early adoption is permitted.

As the amendments apply to income tax disclosures only, the Company does not expect adoption to have a material impact on our consolidated financial statements.

Adoption of Accounting Standards Issued Prior to 2023

Simplifying the Accounting for Income Taxes — In December 2019, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2019-12, Simplifying the Accounting for Income Taxes (Topic 740) .

The ASU enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences.

The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill.

We adopted all provisions of this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.

Changes to the Disclosure Requirements for Fair Value Measurement — In August 2018, the FASB issued ASU 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement.

The ASU removes disclosure requirements for (a) the reasons for transfers between Level 1 and Level 2, (b) the policy for timing of transfers between levels and (c) the valuation processes for Level 3.

The ASU requires new disclosures around (a) the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and (b) the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements.

We adopted this ASU in the first quarter of 2020, and the updated disclosures are included in Note 14.

Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract — In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.

The ASU requires a customer in a cloud hosting arrangement that is a service contract to determine which implementation costs to capitalize and which costs to expense based on the project stage of the implementation.

The ASU also requires the customer to expense the capitalized implementation costs over the term of the hosting arrangement.

The customer is required to apply the existing impairment and abandonment guidance on the capitalized implementation costs.

We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.

Financial Instruments — Credit Losses — In June 2016, the FASB issued ASU 2016-13, Financial Instruments — Credit Losses .

The ASU requires organizations to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts.

We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.

Facilitation of the Effects of Reference Rate Reform on Financial Reporting — In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848):

Facilitation of the Effects of Reference Rate Reform on Financial Reporting

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848):

Facilitation of the Effects of Reference Rate Reform on Financial Reporting .

The ASU provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued.

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Additionally, we have identified the financial instruments to which the expedients could be applied, if deemed necessary, as amendments to these financial instruments are made through the sunset date.

Disclosures by Business Entities about Government Assistance

In November 2021, the Financial Accounting Standards Board issued ASU 2021-10, Government Assistance (Topic 832) Disclosures by Business Entities about Government Assistance .

This standard requires additional annual disclosures when a business receives government assistance and uses a grant or contribution accounting model by analogy to other accounting guidance such as the grant model under International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance (IAS 20) and GAAP ASC 958-605, Not-for-Profit Entities - Revenue Recognition .

The standard was effective January 1, 2022 with early adoption permitted.

As further discussed in Note 1, we made disclosures in accordance with this guidance when accounting for the Uplift Securitization Proceeds from ERCOT.

Due to the enactment of the IRA, the Company qualifies for tax incentives through eligible construction spending and production.

These tax incentives generally provide for refundable or transferable tax credits upon the applicable qualifying event for the credit type, typically production or in-service date.

Transferable and refundable PTCs are included in other noncurrent assets in the consolidated balance sheet and included in revenues in the consolidated statements of operations when receipt of the credit is reasonably assured.

Transferable investment tax credits (ITCs) are included in other noncurrent assets on the consolidated balance sheet with a corresponding reduction to the cost basis of the Company's plant assets when receipt of the credit is reasonably assured, and reduces depreciation expense over the life of the asset.

We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined in ASC 450-20 of U.S.

The Company accounts for the credits we expect to receive by analogy to the grant model within IAS 20, as U.S.

GAAP does not address how to account for these tax credits.

TRANSACTION AGREEMENT

On March 6, 2023, Vistra Operations and Merger Sub entered into the Transaction Agreement with Energy Harbor pursuant to which, upon the terms and subject to the conditions thereof, Merger Sub will be merged with and into Energy Harbor, with Energy Harbor surviving as an indirect subsidiary of Vistra.

The Transaction Agreement, the Merger and the other Transactions were approved by each of Vistra's Board and Energy Harbor's board of directors.

Subject to the terms and conditions of the Transaction Agreement, prior to the consummation of the Merger, Vistra will cause certain of its affiliates to transfer certain of its affiliate entities, including Merger Sub, to an indirect wholly owned subsidiary of Vistra (Vistra Vision).

Subject to the terms and conditions of the Transaction Agreement, at the effective time of the Merger (Effective Time), the issued and outstanding shares of Energy Harbor common stock other than shares that are being exchanged by certain funds and accounts managed by Nuveen Asset Management LLC and certain funds managed by Avenue Capital Management II, L.P.

(Rollover Holders) for 15 % of the direct or indirect equity interests in Vistra Vision, and certain other shares, each as specified in the Transaction Agreement and the Contribution and Exchange Agreements (as defined below) will be cancelled and extinguished and automatically converted into the right to receive cash consideration per share payable in the Merger.

Vistra's transfer of cash and equity in Vistra Vision in exchange for the issued and outstanding shares of Energy Harbor common stock will be covered under the non-recognition provisions of the Internal Revenue Code.

The Aggregate Base Transaction Value is defined in the Transaction Agreement to be (a) the Aggregate Cash Consideration Value (defined in the Transaction Agreement to be $ 3.0 billion), plus (b) for the 15 % equity in Vistra Vision, the Aggregate Equity Consideration Value (defined in the Transaction Agreement to be $ 3.333 billion for the purpose of determining the amount per share to be distributed to Energy Harbor's stockholders), minus (c) certain adjustments as specified in the Transaction Agreement.

In addition, in connection with the Merger, Energy Harbor's equity awards will be cancelled for cash based on the per share Merger consideration for the shares underlying such equity awards and Energy Harbor's stockholders (including Rollover Holders and holders of Energy Harbor equity awards) will receive an additional amount of cash paid from Energy Harbor to the extent of Energy Harbor's unrestricted cash on hand as of the closing, subject to certain adjustments as specified in the Transaction Agreement.

In addition, Vistra Operations will pay up to $ 100 million of Energy Harbor's transaction expenses.

On February 16, 2024, we received approval from FERC to acquire Energy Harbor, which was the last regulatory approval needed to close the acquisition.

Consummation of the Transactions is subject to customary closing conditions, and we anticipate closing on March 1, 2024.

Vistra Vision will combine Energy Harbor's nuclear and retail businesses with Vistra's nuclear and retail businesses and certain of the Vistra Zero renewables and energy storage projects.

This combination is expected to create a leading integrated retail electricity and zero-carbon generation company with the second-largest competitive nuclear fleet in the U.S., along with a growing renewables and energy storage portfolio.

This transaction is expected to accelerate Vistra's path to a clean energy transition by more than doubling the amount of zero-carbon generation it has online at the time of the Transactions' closing.

Financing Arrangements

In connection with the Transactions, in March 2023, Vistra Operations entered into a debt commitment letter (Commitment Letter) and related fee letters with various lenders (Commitment Parties), pursuant to which, and subject to the terms and conditions set forth therein, the Commitment Parties committed to provide (a) up to approximately $ 3.0 billion in an aggregate principal amount of senior secured bridge loans under a 364-day senior secured bridge loan credit facility (Acquisition Bridge Facility), (b) in the event Vistra Operations did not obtain certain required consents and amendments from the lenders under the Vistra Operations Credit Agreement, a 364-day senior secured term loan B bridge facility in an aggregate principal amount of up to approximately $ 2.5 billion (TLB Refinancing Bridge Facility) and (c) in the event Vistra Operations did not obtain certain required consents and amendments from the lenders under the Vistra Operations Commodity-Linked Credit Agreement, a replacement commodity-linked revolving credit facility in an aggregate principal amount up to $ 300 million (Refinancing Commodity-Linked Revolving Credit Facility).

Vistra Operations subsequently obtained commitments from the lenders under the Vistra Operations Credit Agreement and Vistra Operations Commodity-Linked Credit Agreement to provide the required consents and amendments which resulted in the termination of the commitments for each of the TLB Refinancing Bridge Facility and the Refinancing Commodity-Linked Revolving Credit Facility.

In September 2023, the Acquisition Bridge Facility was terminated as a result of the issuance of $ 1.75 billion of a combination of senior secured and senior unsecured notes by Vistra Operations in September 2023 that are expected to be used, together with cash on hand, to fund the Transactions.

Fees related to the Commitment Letter totaled $ 21 million in the year ended December 31, 2023 which were classified as interest expense and related charges in the consolidated statement of operations.

DEVELOPMENT OF GENERATION FACILITIES

Texas Segment Solar Generation and Energy Storage Projects

In September 2020, we announced the planned development of up to 768 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas.

Of this planned development in Texas, 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 to be developed are expected to be 2024 and beyond, but we will only invest in growth projects if we are confident in the expected returns.

In connection with our previously announced renewable development plans in Texas, 158 MW of solar generation came online in January and February 2022 and 260 MW of battery ESS came online in April 2022.

Estimated commercial operation dates for the remaining facilities to be developed are expected to be 2025 and beyond, but we will only invest in growth projects if we are confident that the expected returns will meet or exceed internal targets.

As of December 31, 2023, we had accumulated approximately $ 200 million in construction-work-in-process for these remaining Texas segment solar generation projects.

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West Segment Energy Storage Projects

Oakland — In June 2019, East Bay Community Energy (EBCE) signed a 10 -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).

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.

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 battery ESS.

Moss Landing Phase I commenced commercial operations in May 2021.

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Moss Landing Phase II commenced commercial operations in July 2021.

The total development costs for Moss Landing Phases I and II totaled approximately $ 600 million.

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.

As of December 31, 2022, we had accumulated approximately $ 288 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.

Moss Landing Phase III commenced commercial operations in June 2023.

As a result of reaching commercial operations, we recognized $ 154 million of transferable ITCs associated with the project within other noncurrent assets in the consolidated balance sheet.

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.

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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.

Retirement date represents the first full day in which a plant does not operate.

Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Actual or Expected Retirement Date (a) Segment

Facility Location ISO/RTO Fuel Type Net Generation Capacity (MW) Actual or Expected Retirement Date (a)(b) 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 Retired 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

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Newton Newton, IL MISO/PJM Coal 615 By the end of 2027 Sunset

Edwards Bartonville, IL MISO Coal 585 Retired January 1, 2023 Asset Closure

Joppa Joppa, IL MISO Coal 802 Retired September 1, 2022 Asset Closure

Joppa Joppa, IL MISO Natural Gas 221 Retired September 1, 2022 Asset Closure

Zimmer Moscow, OH PJM Coal 1,300 Retired June 1, 2022 Asset Closure

(a) Generation facilities may retire earlier than the end of 2027 if economic or other conditions dictate.

(a) Generation facilities may retire earlier than expected dates disclosed if economic or other conditions dictate.

(b) Retirement dates represent the first full day in which a plant does not operate.

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 14), and in furtherance of our efforts to significantly reduce our carbon footprint.

Expected plant retirement expenses of $ 31 million and $ 12 million, respectively, driven by severance cost, were accrued in the year ended December 31, 2020 in operating costs of our Sunset and Asset Closure segments, respectively.

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.

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See Note 22 for discussion of impairments recorded in connection with these determinations.

Revenue Disaggregation

The following tables disaggregate our revenue by major source:

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Intangible amortization ( 1 ) — ( 2 ) — ( 3 ) — — ( 6 )

Transferable PTC revenues — 10 — — — — — 10

Hedging and other revenues (b) 1,257 ( 1,611 ) 277 310 736 — 2 971

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The Sunset segment includes $ 76 million of capacity sold offset by $ 35 million of capacity purchased.

The Asset Closure segment includes $ 20 million of capacity sold.

(b) Includes $ 2.163 billion of unrealized net losses from mark-to-market valuations of commodity positions, including Retail segment unrealized net losses of $ 544 million due to the discontinuance of NPNS accounting on retail electric contract portfolios in the second quarter of 2022 and the third quarter of 2021 where physical settlement is no longer considered probable throughout the contract term.

See Note 19 for unrealized net gains (losses) by segment.

(c) Texas and East segments include $ 817 million and $ 38 million, respectively, of affiliated unrealized net losses, and Sunset segment includes $ 34 million of affiliated unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

(b) Includes $ 714 million of unrealized net gains from mark-to-market valuations of commodity positions.

For the year ended Retail Texas East West Sunset Asset Closure Corporate and Other Eliminations (1) Consolidated

December 31, 2023 $ 191 $ ( 758 ) $ 1,165 $ 237 $ 603 $ 36 $ — $ ( 760 ) $ 714

(1) Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.

(c) East and Sunset segments include $ 641 million and $ 187 million, respectively, of affiliated unrealized net gains, and Texas segment includes $ 62 million of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Year Ended December 31, 2022

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(a) Represents net capacity sold (purchased) in each ISO/RTO.

The East segment includes $ 470 million of capacity purchased offset by $ 448 million of capacity sold.

The West segment includes $ 1 million of capacity sold.

The East segment includes $ 302 million of capacity sold offset by $ 282 million of capacity purchased.

The Sunset segment includes $ 59 million of capacity sold offset by $ 3 million of capacity purchased.

The Asset Closure segment includes $ 27 million of capacity sold.

(b) Includes $ 1.191 billion of unrealized net losses from mark-to-market valuations of commodity positions, including Retail segment unrealized net losses of $ 298 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 19 for unrealized net gains (losses) by segment.

(c) Texas, East and Sunset segments include $ 1.028 billion, $ 529 million and $ 162 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

(b) Includes $ 2.163 billion of unrealized net losses from mark-to-market valuations of commodity positions.

For the year ended Retail Texas East West Sunset Asset Closure Corporate and Other Eliminations (1) Consolidated

December 31, 2022 ( 532 ) ( 1,472 ) ( 757 ) ( 324 ) ( 3 ) 106 — 819 ( 2,163 )

(1) Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.

(c) Texas and East segments include $ 817 million and $ 38 million, respectively, of affiliated unrealized net losses, and Sunset and Asset Closure segment includes $ 30 million and $ 4 million, respectively, of affiliated unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

Year Ended December 31, 2021

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Hedging and other revenues (b) ( 115 ) ( 4,355 ) 123 35 ( 929 ) ( 442 ) — ( 5,683 )

Affiliate sales — 2,999 1,595 3 298 — ( 4,895 ) —

Affiliate sales (c) — 1,035 1,024 5 238 ( 18 ) ( 2,284 ) —

Total other revenues ( 117 ) ( 3,320 ) 1,221 40 ( 703 ) ( 460 ) ( 2,284 ) ( 5,623 )

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The East segment includes $ 470 million of capacity purchased offset by $ 448 million of capacity sold.

The West segment includes $ 1 million of capacity sold.

The Sunset segment includes $ 126 million of capacity sold offset by $ 4 million of capacity purchased.

The Asset Closure segment includes $ 62 million of capacity sold.

(b) Includes $ 164 million of unrealized net gains from mark-to-market valuations of commodity positions.

See Note 19 for unrealized net gains (losses) by segment.

(b) Includes $ 1.191 billion of unrealized net losses from mark-to-market valuations of commodity positions.

For the year ended Retail Texas East West Sunset Asset Closure Corporate and Other Eliminations (1) Consolidated

December 31, 2021 ( 325 ) ( 1,272 ) ( 637 ) ( 42 ) ( 394 ) ( 240 ) — 1,719 ( 1,191 )

(1) Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.

(c) Texas, East, Sunset and Asset Closure segments include $ 1.028 billion, $ 529 million, $ 144 million and $ 18 million respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Retail Energy Charges

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The penalties are recorded as a reduction to revenue.

When capacity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in capacity revenue.

Revenue from Other Wholesale Contracts

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Other Revenues

Other revenues, as included in the tables of disaggregated revenue above, represent amounts not accounted for under ASC 606, Revenue from Contracts with Customers and are comprised of intangible amortization, hedging and other revenues and affiliate sales.

• Intangible amortization represents amortization of acquired intangible liabilities related to retail and wholesale contracts (see Note 6).

• Some of our contracts for the sale of electricity meet the definition of a derivative under the accounting standards related to derivative instruments.

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Our revenue from the sale of electricity under derivative contracts, including the impact of unrealized gains or losses on those contracts, is reported in the table above as hedging and other revenues.

We have classified all sales to affiliates that are eliminated in consolidation as other revenues in the table above.

• Sales to affiliates are presented by segment and eliminated in consolidation.

Contract and Other Customer Acquisition Costs

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Accounts Receivable

The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both contracts with customers and other activities:

The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both ASC 606, Revenue from Contracts with Customers and other activities:

Trade accounts receivable from contracts with customers — net $ 1,239 $ 1,644

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GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

The following table provides information regarding our goodwill balance.

Balance at December 31, 2019 $ 2,553

Measurement period adjustments recorded in 2020 in connection with the Crius Transaction ( 14 )

Measurement period adjustments recorded in 2020 in connection with the Ambit Transaction 44

Balance at December 31, 2022, 2021 and 2020 $ 2,583

As of December 31, 2022, the carrying value of goodwill totaled $ 2.583 billion and consisted of the following:

• $ 1.907 billion arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to our Retail reporting unit.

Of the goodwill recorded at Emergence, $ 1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.

• $ 175 million arose in connection with the Merger, of which $ 122 million was allocated to our Texas Generation reporting unit and $ 53 million was allocated to our Retail reporting unit.

None of the goodwill related to the Merger is deductible for tax purposes.

• $ 243 million of goodwill arose in connection with the Crius Transaction and was allocated entirely to our Retail reporting unit.

None of the goodwill related to the Crius Transaction is deductible for tax purposes.

• $ 258 million of goodwill arose in connection with the Ambit Transaction and was allocated entirely to our Retail reporting unit.

The goodwill related to the Ambit Transaction is deductible for tax purposes over 15 years on a straight-line basis.

As of both December 31, 2023 and 2022, the carrying value of goodwill totaled $ 2.583 billion as there were no additions or impairments in the years then ended.

The carrying value of goodwill as of each date consists of the following:

Reportable Segment Reporting Unit Carrying Value of Goodwill

Texas Texas Generation $ 122

Retail (a) Retail 2,461

Total $ 2,583

(a) $ 1.944 billion of goodwill is deductible for tax purposes over 15 years on a straight-line basis.

Goodwill is required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist.

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Retail and wholesale contracts 233 217 16 233 209 24

Contractual service agreements (a) 18 4 14 23 2 21

Other identifiable intangible assets (b) 50 8 42 95 20 75

LTSA 18 5 13 18 4 14

Other identifiable intangible assets (a) 62 11 51 50 8 42

Total identifiable intangible assets subject to amortization $ 2,937 $ 2,414 523 $ 2,864 $ 2,247 617

Retail trade names (not subject to amortization) (c) 1,341 1,341

Retail trade names (not subject to amortization) 1,341 1,341

Total identifiable intangible assets $ 1,864 $ 1,958

(a) As of December 31, 2022 and 2021, 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).

(c) During the year ended December 31, 2021, we recorded a $ 33 million impairment to a retail trade name intangible asset .

(a) Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).

Identifiable intangible liabilities are comprised of the following:

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Identifiable Intangible Liability 2023 2022

Contractual service agreements

Purchase and sale of power and capacity

Fuel and transportation purchase contracts

Other identifiable intangible liabilities — 3

Total identifiable intangible liabilities $ 131 $ 140

Expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the consolidated statements of operations) consisted of:

Identifiable Intangible Assets and Liabilities Consolidated Statements of Operations Remaining useful lives of identifiable intangible assets at December 31,

Expense related to finite-lived identifiable intangible assets (including the classification in the consolidated statements of operations) consisted of:

Identifiable Intangible Assets Consolidated Statements of Operations Remaining useful lives of identifiable intangible assets at December 31,

2023 (weighted average in years) Year Ended December 31,

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Software and other technology-related assets Depreciation and amortization 4 58 69 74

Retail and wholesale contracts/purchase and sale/fuel and transportation contracts Operating revenues/fuel, purchased power costs and delivery fees 3 7 ( 56 ) 17

Other identifiable intangible assets Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization 4 391 279 223

Total intangible asset expense, net (a) $ 604 $ 494 $ 596

Retail and wholesale contracts Operating revenues/fuel, purchased power costs and delivery fees 3 8 7 ( 56 )

Other identifiable intangible assets Fuel, purchased power costs and delivery fees 5 357 391 279

Total intangible asset expense (a) $ 521 $ 604 $ 494

(a) Amounts recorded in depreciation and amortization totaled $ 158 million, $ 208 million and $ 275 million for the years ended December 31, 2023, 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 consolidated statements of operations.

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The following is a description of the separately identifiable intangible assets.

In connection with fresh start reporting, the Merger, the Crius Transaction and the Ambit Transaction, the intangible assets were adjusted based on their estimated fair value as of the Effective Date, the Merger Date, the Crius Acquisition Date and the Ambit Acquisition Date, respectively, based on observable prices or estimates of fair value using valuation models.

In connection with fresh start reporting, the Dynegy Merger, the Crius Transaction and the Ambit Transaction, the intangible assets were adjusted based on their estimated fair value as of the Effective Date, the Dynegy Merger Date, the Crius Acquisition Date and the Ambit Acquisition Date, respectively, based on observable prices or estimates of fair value using valuation models.

• Retail customer relationship — Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is being amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.

• Retail and wholesale contracts — These intangible assets represent the value of various acquired retail and wholesale contracts and fuel and transportation purchase contracts.

The contracts were identified as either assets or liabilities based on the respective fair values as of the Effective Date, the Dynegy Merger Date, the Crius Acquisition Date or the Ambit Acquisition Date utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements.

The intangible assets or liabilities are being amortized in relation to the economic terms of the related contracts.

• LTSA — Our acquired LTSA represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements and are being amortized based on the expected usage of the service agreements over the contract terms.

The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant and equipment.

• Retail trade names — Our retail trade name intangible assets represent the fair value of our retail brands, including the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power and U.S.

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On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2023.

• Retail and wholesale contracts/purchase and sale contracts — These intangible assets represent the value of various retail and wholesale contracts and purchase and sale contracts.

The contracts were identified as either assets or liabilities based on the respective fair values as of the Effective Date, the Merger Date, the Crius Acquisition Date or the Ambit Acquisition Date utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements.

The intangible assets or liabilities are being amortized in relation to the economic terms of the related contracts.

• Contractual service agreements — Our acquired contractual service agreements represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements and are being amortized based on the expected usage of the service agreements over the contract terms.

The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant and equipment.

Estimated Amortization of Identifiable Intangible Assets and Liabilities

As of December 31, 2022, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.

Estimated Amortization of Identifiable Intangible Assets

As of December 31, 2023, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.

Year Estimated Amortization Expense

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State tax, net of federal benefit 86 ( 19 ) ( 2 )

Federal and State return to provision adjustment ( 15 ) ( 2 ) 13

Nondeductible compensation 5 4 —

Equity awards ( 3 ) 1 —

Valuation allowance on state NOLs ( 20 ) ( 8 ) ( 94 )

Lignite depletion ( 4 ) ( 3 ) ( 3 )

Release of Uncertain Tax Positions ( 35 ) — —

Other 16 ( 13 ) 8

Income tax expense (benefit) $ 508 $ ( 350 ) $ ( 458 )

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As of December 31, 2023, we had total net deferred tax assets of approximately $ 1.22 billion that were substantially comprised of book and tax basis differences related to our generation and mining property, plant and equipment, as well as federal and state net operating loss (NOL) carryforwards.

Our deferred tax assets were significantly impacted by the impacts of Winter Storm Uri as well as the Merger.

Our deferred tax assets were significantly impacted by the impacts of Winter Storm Uri as well as the Dynegy Merger.

For the year ended December 31, 2023, we recognized a tax benefit of $ 20 million on the release of state valuation allowances.

For the year ended December 31, 2022, we recognized a tax benefit of $ 9 million on the release of state valuation allowances.

For the year ended December 31, 2021, we recognized a tax benefit of $ 74 million on the release of state valuation allowances largely related to Illinois.

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As of December 31, 2023, we had $ 4.0 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2032.

The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax liabilities of $ 7 million and $ 9 million at December 31, 2022 and 2021, respectively.

The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax liabilities of zero and $ 7 million at December 31, 2023 and 2022, respectively.

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S.

enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including a nuclear production tax credit (PTC), a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15 % corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1 % excise tax on net stock repurchases.

Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months.

Vistra is not subject to the CAMT in the next fiscal year since it applies only to corporations that have 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.

As of December 31, 2022, we have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes for periods after the law takes effect 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 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.

enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including a nuclear PTC, a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15 % corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1 % excise tax on net stock repurchases.

Treasury regulations are expected to further define the scope of the legislation in many important respects over the next twelve months.

The excise tax on stock repurchases is not expected to have a material impact on our financial statements.

Vistra is not subject to the CAMT in the 2023 tax year since it applies only to corporations that have a three-year average annual adjusted financial statement income in excess of $ 1 billion.

We have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes for periods after the law takes effect.

See Note 1 for our accounting policy related to refundable and transferable PTCs and ITCs.

Final Section 163(j) Regulations

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 enacted, Vistra's deductible business interest expense will be significantly limited for the 2022 tax year.

As a result, under the law as currently enacted, Vistra's deductible business interest expense has been significantly limited for the 2023 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 also utilized the CARES Act payroll deferral mechanism to defer the payment of approximately $ 22 million from 2020 to 2021 and 2022.

We paid the remainder of the previously deferred taxes in December 2022.

Liability for Uncertain Tax Positions

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Reductions based on tax positions related to prior years — ( 1 ) —

Reductions related to the lapse of the tax statute of limitations ( 35 ) — —

Settlements with taxing authorities ( 1 ) ( 1 ) ( 2 )

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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.

The federal income tax audit is in its final stages and Vistra expects final closing on an agreed basis with immaterial changes in the first half of 2023.

It is reasonably possible $ 36 million of the uncertain tax positions could be resolved within the next 12 months upon final closing.

In December 2022, the IRS formally concluded the federal income tax examination of Crius Energy Corp's pre-acquisition tax years 2015 and 2016, with payment of the agreed adjustments of less than $ 1 million made in 2022.

All adjustments were agreed, closing out tax years 2015 and 2016.

Uncertain tax positions totaled $ 36 million and $ 38 million as of December 31, 2022 and 2021, respectively.

In February 2021, Vistra was notified that the IRS had opened a federal income tax audit for tax years 2018 and 2019.

The federal income tax audit was closed in June 2023 with immaterial changes.

Uncertain tax positions totaled zero and $ 36 million as of December 31, 2023 and 2022, respectively.

Of the amounts recorded as unrecognized tax benefits, an insignificant portion would impact our effective tax rate if recognized.

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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.

Pursuant to the TRA, we issued 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 20).

As of January 1, 2023, 426,369,370 of TRA Rights were outstanding.

In December 2023, Vistra repurchased (Repurchase) approximately 74 % of the TRA Rights to receive payments under the TRA from a select group of registered holders of the TRA Rights (Selling Holders) in exchange for consideration of $ 1.50 per repurchased TRA Right, totaling an aggregate purchase price for the Repurchase of approximately $ 476 million.

The consideration for the Repurchase was paid through the issuance of 476,081 shares of Series C Preferred Stock (see Note 15) to the Selling Holders in a transaction exempt from registration pursuant to Section 4(a)(2) of the Securities Act.

As part of the transaction, the Company agreed to file a shelf registration statement on Form S-3 registering the resale of the shares by the Selling Holders of Series C Preferred Stock from time to time under Rule 415 of the Securities Act, which was filed on January 29, 2024.

If the Company repurchases TRA Rights at any time during the 180 days following December 29, 2023 at a price per TRA Right greater than $ 1.50 , the Company will pay the Selling Holders an amount equal to such excess purchase price per TRA Right sold by the Selling Holders.

In connection with the Repurchase, holders of approximately 74 % of the outstanding TRA Rights consented to certain amendments to the TRA which were effected in an Amended and Restated Tax Receivables Agreement (A&R TRA), dated as of December 29, 2023.

Such amendments to the TRA include (i) the removal of the Company's obligation to provide registered holders of the TRA Rights (Holders) with regular reporting and access to information, (ii) limitations on the transferability of the TRA Rights, (iii) removal of certain obligations of the Company in the event it incurs indebtedness and (iv) a change to the definition of "Change of Control."

In connection with the Repurchase, in the year ended December 31, 2023, we recognized a $ 29 million gain in other income in our consolidated statements of operations.

The gain represents the difference between the $ 506 million carrying value of the portion of the TRA liability that was repurchased and the $ 476 million fair value of the Series C Preferred Stock issued.

On January 11, 2024, Vistra repurchased an additional 43,494,944 of outstanding TRA Rights from a select group of registered holders of TRA Rights in exchange for consideration of $ 1.50 per repurchased TRA Right.

Total consideration of $ 65 million was paid using cash on hand.

On January 31, 2024, Vistra announced a cash tender offer to purchase any and all outstanding TRA Rights in exchange for consideration of $ 1.50 per tendered TRA Right accepted for purchase prior to close of business on February 13, 2024 (Early Tender Date), which included an early tender premium of $ 0.05 per TRA Right accepted for purchase.

As of the Early Tender Date, 55,056,931 TRA Rights were accepted for purchase for total consideration of $ 83 million, which was paid using cash on hand.

TRA Rights accepted for purchase after the Early Tender Date, but prior to close of business on February 28, 2024, will receive consideration of $ 1.45 per TRA Right accepted for purchase, which will be paid using cash on hand.

As of the Early Tender Date, we have repurchased an aggregate 98 % of the original outstanding TRA Rights, of which 10,430,083 TRA Rights remain outstanding.

The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our consolidated balance sheets, for the years ended December 31, 2023, 2022 and 2021.

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Payments ( 9 ) ( 1 ) ( 2 )

Repurchase of TRA Rights ( 506 ) — —

TRA obligation at the end of the period 171 522 395

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Noncurrent TRA obligation at the end of the period $ 164 $ 514 $ 394

(a) During the year ended December 31, 2022, we recorded an increase to the carrying value of the TRA obligation totaling $ 64 million as a result of adjustments to forecasted book and taxable income due to increases in commodity price forecasts.

During the year ended December 31, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling approximately $ 115 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.

During the year ended December 31, 2020, we recorded a decrease to the carrying value of the TRA obligation totaling $ 69 million as a result of adjustments to forecasted taxable income, including the impacts of the CARES Act, changes to Section 163(j) percentage limitation amount, the impacts from the issuance of the final Section 163(j) regulations and the anticipated tax benefits from renewable development projects.

(a) During the year ended December 31, 2023, we recorded an increase to the carrying value of the TRA obligation totaling $ 82 million as a result of adjustments to forecasted taxable income due to increases in longer-term commodity price forecasts.

During the year ended December 31, 2022, we recorded an increase to the carrying value of the TRA obligation totaling approximately $ 64 million as a result of adjustments to forecasted book and taxable income due to increases in commodity price forecasts.

During the year ended December 31, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $ 115 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 December 31, 2023, the estimated carrying value of the TRA obligation totaled $ 171 million, which represents the discounted amount of projected payments under the TRA.

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These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation.

As of December 31, 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).

As of December 31, 2023, and excluding the January and February 2024 activity discussed above, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $ 350 million, 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.

The TRA provides that, in the event that Vistra breaches any of its material obligations under the TRA, or upon certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under the TRA may treat such event as an early termination of the TRA, in which case Vistra would be required to make an immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits based on certain valuation assumptions.

The TRA provides that, in the event that Vistra breaches any of its material obligations under the TRA, or upon certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under the TRA may treat such event as an early termination of the TRA, in which case Vistra would be required to make an immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to three-month CME Term SOFR plus the tenor spread adjustment of 0.26161 % plus 100 basis points) of the anticipated future tax benefits based on certain valuation assumptions.

The LIBOR provisions of the TRA are subject to the Adjustable Interest Rate (LIBOR) Act of 2022 (LIBOR Act) and the regulations promulgated to carry out the LIBOR Act (LIBOR Regulations).

With respect to payments under the TRA, pursuant to the LIBOR Act and the LIBOR Regulations, the "Board-selected benchmark replacement" (BSBR) of three-month CME Term SOFR plus the tenor spread adjustment of 0.26161 % automatically became the benchmark replacement to three-month LIBOR on July 1, 2023 and, in addition, the four conforming changes promulgated by the Federal Reserve System Board in the LIBOR Regulations (each of which is a technical or administrative in nature) also apply to the TRA, by operation of law, to effectuate the implementation and use of the foregoing BSBR.

EARNINGS PER SHARE

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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.

Cumulative dividends attributable to Series C Preferred Stock were immaterial during the year ended December 31, 2023.

Year Ended December 31,

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Less cumulative dividends attributable to Series B Preferred Stock ( 70 ) ( 70 ) ( 4 )

Less cumulative dividends attributable to Series C Preferred Stock — — —

Net income (loss) attributable to common stock — basic 1,343 ( 1,377 ) ( 1,295 )

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TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers).

In December 2020, the Receivables Facility was amended to include Ambit Texas, LLC (Ambit Texas), Value Based Brands and TriEagle Energy, as originators, and increase the commitment of the Purchasers to $ 500 million for the remaining term of the Receivables Facility.

In February 2021, the Receivables Facility was amended to allow for a one-time, $ 596 million borrowing to take advantage of a higher receivable balance at such time.

The borrowing limit returned to $ 500 million in March 2021.

In March 2021, the Receivables Facility was amended to increase the commitment of the Purchasers to $ 600 million through the July 2021 renewal.

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 which increased the commitments by $ 25 million for the settlement periods through December 2022 as compared to prior 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.

The Receivables Facility was renewed in July 2023, extending the term of the Receivables Facility to July 2024 and adjusting the commitment of the purchasers to purchase interests in the receivables under the Receivables Facility during all periods to a fixed purchase limit of $ 750 million from seasonally adjusted commitment limits ranging from $ 600 million to $ 750 million.

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.

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TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable.

As of December 31, 2022, outstanding borrowings under the Receivables Facility totaled $ 425 million and were supported by $ 1.013 billion of RecCo gross receivables.

As of December 31, 2023, there were no outstanding borrowings under the Receivables Facility.

As of December 31, 2022, outstanding borrowings under the Receivables totaled $ 425 million and were supported by $ 1 billion of RecCo gross receivables.

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 2021, the Repurchase Facility was renewed until August 2021 and increased from $ 125 million to $ 150 million.

In August 2021, the Repurchase Facility was renewed until July 2022 and the facility size was decreased from $ 150 million to $ 125 million.

In August 2022, the Repurchase Facility was renewed until July 2023 while maintaining the facility size of $ 125 million.

In July 2023, the Repurchase Facility was renewed until July 2024 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.

Each Repo Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.

TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility.

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There were no outstanding borrowings under the Repurchase Facility as of both December 31, 2023 and December 31, 2022.

COLLATERAL FINANCING AGREEMENT WITH AFFILIATE

On June 15, 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed by the Company (the Trust) that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $ 450 million.

The Trust is not consolidated by Vistra.

The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S.

Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S.

dollars, the Eligible Assets).

At the direction of Vistra Operations, the Eligible Assets held by the Trust can be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program.

Fees related to the Facility Agreement transaction totaled $ 7 million in the year ended December 31, 2023, which were capitalized as other noncurrent assets.

Under the Facility Agreement, Vistra Operations has the right (Issuance Right), from time to time, to require the Trust to purchase from Vistra Operations up to $ 450 million aggregate principal amount of Vistra Operations' 7.233 % Senior Secured Notes due 2028 ( 7.233 % Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury Strips corresponding to the portion of the issuance right exercised at such time.

The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233 % Senior Secured Notes to the holders of the P-Caps if its sole assets consist of 7.233 % Senior Secured Notes that Vistra Operations is no longer entitled to repurchase.

Vistra Operations pays a facility fee (Facility Fee) to the Trust payable on each May 17 and November 17, commencing on November 17, 2023, to and including May 17, 2028 (each, a Distribution Date), and on certain other dates as provided in the Facility Agreement.

The Facility Fee is generally calculated at a rate of 3.3608 % per annum, applied to the maximum amount of 7.233 % Senior Secured Notes that Vistra Operations could issue and sell to the Trust under the Facility Agreement as of the close of business on the business day immediately preceding the applicable Distribution Date.

As of December 31, 2023, $ 439 million is the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements and is reported in our consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposit financing with affiliate.

Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company.

Vistra Operations Credit Facilities $ 2,514 $ 2,543

Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 $ 2,500 $ 2,514

Vistra Operations Senior Secured Notes:

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4.300 % Senior Secured Notes, due July 15, 2029

6.950 % Senior Secured Notes, due October 15, 2033

Total Vistra Operations Senior Secured Notes 5,650 4,600

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4.375 % Senior Unsecured Notes, due May 15, 2029

7.750 % Senior Unsecured Notes, due October 15, 2031

Total Vistra Operations Senior Unsecured Notes 6,300 4,850

Forward Capacity Agreements — 213

Equipment Financing Agreements 67 79

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Total long-term debt including amounts due currently 14,402 11,971

Less amounts due currently ( 38 ) ( 254 )

Less amounts due currently (a) ( 2,286 ) ( 38 )

Total long-term debt less amounts due currently $ 12,116 $ 11,933

As of December 31, 2022 and 2021, outstanding short-term borrowings totaled $ 650 million and zero , respectively, under the Commodity-Linked Facility and the Revolving Credit Facility (described below).

(a) Includes $ 356 million of the 5.125 % senior secured notes due 2025 repurchased for cash as part of the Senior Secured Notes Tender Offer in January 2024 (described below) as the payment was made with current assets on our consolidated balance sheet as of December 31, 2023.

As of December 31, 2023 and 2022, outstanding short-term borrowings under the Revolving Credit Facility and the Commodity-Linked Facility (each described below) totaled zero and $ 650 million, respectively.

Vistra Operations Credit Facilities and Commodity-Linked Revolving Credit Facility

Vistra Operations Credit Facilities — As of December 31, 2022, the Vistra Operations Credit Facilities consisted of up to $ 5.889 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $ 3.375 billion (Revolving Credit Facility) and term loans of $ 2.514 billion (Term Loan B-3 Facility).

Vistra Operations Credit Facilities

As of December 31, 2023, the Vistra Operations Credit Facilities consisted of up to $ 5.675 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $ 3.175 billion (Revolving Credit Facility) and term loans of $ 2.5 billion (Term Loan B-3 Facility).

These amounts reflect the following transactions and amendments completed in 2023, 2022 and 2021:

• 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.

• On December 20, 2023, Vistra Operations entered into an amendment (December 2023 Credit Agreement Amendment) to the Vistra Operations Credit Agreement among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, the 2023 Incremental Term Loan Lender, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, and other parties named therein.

Pursuant to the December 2023 Credit Agreement Amendment, (i) incremental term loans totaling $ 7 million aggregate principal amount were established and were added to (and made part of) the existing Term Loan B-3 Facility, (ii) the maturity date of the Term Loan B-3 Facility was extended to December 20, 2030, (iii) Credit Suisse AG, Cayman Islands Branch provided notice of its intent to resign as administrative agent, collateral agent and a letter of credit issuer and Vistra Operations and the required lenders agreed to appoint Citibank, N.A.

as successor thereto upon the effectiveness of such resignation, (iv) interest rate margins on the Term SOFR Rate and Alternate Base Rate (ABR) were increased by 25 basis points, and (v) the credit spread adjustment related to the Adjusted Term SOFR Rate applicable to the Term B-3 Facility, as discussed in the April 2023 Credit Agreement Amendment below, was eliminated.

Fees and expenses related to the December 2023 Credit Agreement Amendment of $ 19 million and original issue discount of $ 25 million were capitalized as a reduction in the carrying amount of the debt.

We recorded an extinguishment gain of $ 3 million related to the December 2023 Credit Agreement Amendment in interest expense and other charges in our consolidated statements of operations.

• On September 26, 2023, Vistra Operations entered into (a) an amendment to the Vistra Operations Credit Agreement, among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other parties named therein, and (b) an amendment to the Vistra Operations Commodity-Linked Credit Agreement, among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, Citibank, N.A., as administrative agent, and the other parties named therein (such amendments, the September 2023 Amendments).

The September 2023 Amendments, among other things, (i) implemented changes to certain covenants and other provisions of the Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement, as applicable, to allow for the Energy Harbor acquisition and related additional financings contemplated by the Commitment Letter and (ii) provided for additional operational flexibility in the conduct of Vistra Operation's business.

In addition, the September 2023 amendment to the Vistra Operations Commodity-Linked Credit Agreement also provided Vistra Operations the flexibility to update the deemed hedge portfolio that serves as the borrowing base under the Commodity-Linked Facility on a more frequent basis.

• On April 28, 2023, Vistra Operations entered into an amendment (April 2023 Credit Agreement Amendment) to the Vistra Operations Credit Agreement, among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other parties named therein.

Pursuant to the April 2023 Credit Agreement Amendment, and in light of a public statement by the supervisor for the administrator of the "LIBOR Rate" identifying June 30, 2023 as the date after which the "LIBOR Rate" was to permanently or indefinitely cease to be published, the "LIBOR Rate", with respect to the term loans under the Vistra Operations Credit Agreement, ceased to be applicable after June 30, 2023 and was replaced by the Adjusted Term SOFR Rate, other than as expressly contemplated by the April 2023 Credit Agreement Amendment.

The Adjusted Term SOFR Rate with respect to the Term Loan B-3 Facility was effective through December 20, 2023 and was the interest rate per annum equal to the Term SOFR Rate plus (a) with respect to an interest period of one month, 0.11 % per annum, (b) with respect to an interest period of three months, 0.26 % per annum and (c) with respect to an interest period of six months, 0.43 % per annum.

• On April 29, 2022 (April 2022 Amendment Effective Date) and July 18, 2022 (July 2022 Amendment Effective Date), Vistra Operations entered into amendments (2022 Credit Agreement Amendments) to the Vistra Operations Credit Agreement, among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent, and the other parties named therein.

Pursuant to the 2022 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.

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.

The July 18, 2022 amendment to the Vistra Operations Credit Agreement also provided that Vistra Operations would terminate at least $ 350 million in Extended Revolving Credit Facility (as defined below) 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.

In accordance with this requirement, effective December 30, 2022, Vistra Operations terminated $ 350 million in revolving commitments.

After giving effect to the Credit Agreement Amendments and the revolving commitment reduction, the aggregate amount of revolving commitments maturing on April 29, 2027 equals $ 3.175 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.

Furthermore, the Credit Agreement Amendments appointed 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.

After giving effect to the 2022 Credit Agreement Amendments and the revolving commitment reduction, the aggregate amount of revolving commitments maturing on April 29, 2027 equals $ 3.175 billion (Extended Revolving Credit Facility), while the $ 200 million in revolving commitments that matured on June 14, 2023 (Non-Extended Revolving Credit Facility) remained unchanged by the Credit Agreement Amendments.

Furthermore, the 2022 Credit Agreement Amendments appointed new revolving letter of credit issuers, such that the aggregate amount of revolving letter of credit commitments equals $ 3.105 billion after giving effect to (i) the 2022 Credit Agreement Amendments and (ii) the maturity of the Non-Extended Credit Facility on June 14, 2023 in accordance with the terms of the Vistra Operations Credit Agreement.

Fees and expenses related to the 2022 Credit Agreement Amendments totaled $ 8 million in the year ended December 31, 2022, which were capitalized as a reduction in the carrying amount of the debt.

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We recorded an extinguishment loss of $ 1 million on the transaction in the year ended December 31, 2021.

• In March 2020, Vistra Operations repurchased and cancelled $ 100 million principal amount of Term Loan B-3 Facility borrowings at a weighted average price of $ 93.875 .

We recorded an extinguishment gain of $ 6 million on the transaction in the year ended December 31, 2020.

During the year ended December 31, 2022, we borrowed $ 1.75 billion and repaid $ 1.5 billion under the Revolving Credit Facility, with proceeds from the borrowings used for general corporate purposes.

Our credit facilities and related available capacity at December 31, 2023 are presented below.

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Extended Revolving Credit Facility (a) April 29, 2027 $ 3,175 $ — $ 1,962 $ 1,213

Non-Extended Revolving Credit Facility (b) June 14, 2023 $ 200 $ 13 $ 112 $ 75

Term Loan B-3 Facility (c) December 31, 2025 2,514 2,514 — —

Term Loan B-3 Facility (b) December 20, 2030 2,500 2,500 — —

Total Vistra Operations Credit Facilities $ 5,675 $ 2,500 $ 1,962 $ 1,213

Commodity-Linked Facility (d) October 4, 2023 1,350 400 — 808

Commodity-Linked Facility (c) October 2, 2024 $ 1,575 $ — — $ 1,101

Total Credit Facilities $ 7,250 $ 2,500 $ 1,962 $ 2,314

(a) Extended Revolving Credit Facility used for general corporate purposes.

(a) Extended Revolving Credit Facility is used for general corporate purposes.

Cash borrowings under the Extended Revolving Credit Facility are reported in short-term borrowings in our consolidated balance sheets.

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In December 2022, Vistra Operations terminated $ 350 million in Extended Revolving Credit Facility commitments.

(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 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.

(b) Effective December 20, 2023, cash borrowings under the Term Loan B-3 Facility are subject to required scheduled quarterly payments of $ 6.25 million beginning in March 2024.

Amounts paid cannot be reborrowed.

(d) Commodity-Linked Facility (defined below) used to support our comprehensive hedging strategy.

As of December 31, 2023, the borrowing base of $ 1.101 billion is lower than the facility limit which represents aggregate commitments of $ 1.575 billion.

See Commodity-Linked Revolving Credit Facility below for discussion of the borrowing base calculation.

The Commodity-Linked Facility was amended in October 2023, increasing the aggregate commitments to $ 1.575 billion and extending the term to October 2024.

The deemed hedge portfolio was also updated to reflect current hedge positions, including the addition of the 2025 deemed hedges.

Cash borrowings under the Commodity-Linked Facility are reported in short-term borrowings in our 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 December 31, 2022, there were $ 237 million outstanding borrowings under the Extended Revolving Credit Facility and the weighted average interest rate on outstanding borrowings was 8.25 % based on the Alternate Bank Rate (ABR) plus a spread of 0.75% as required to be used for same-day borrowings.

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.

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 December 31, 2022, there were $ 13 million outstanding borrowings under the Non-Extended Revolving Credit Facility and the weighted average interest rate on outstanding borrowings was 8.25 % based on the ABR plus a spread of 0.75% as required to be used for same-day borrowings.

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 December 31, 2022, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 6.13 % 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.

Under the Vistra Operations Credit Agreement, the interest applicable to the Extended Revolving Credit Facility is based on the forward-looking term rate based on SOFR (Term SOFR Rate) plus a spread that will range from 1.25 % to 2.00 %, 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 will 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 December 31, 2023, the applicable interest rate margins for the Extended Revolving Credit Facility and the fee for undrawn amounts relating to such extended commitments were lowered to 1.70 % and 26.5 basis points, respectively, related to a sustainability pricing adjustment based on certain sustainability-linked targets and thresholds.

As of December 31, 2023, there were no outstanding borrowings under the Extended Revolving Credit Facility.

Letters of credit issued under the Extended Revolving Credit Facility bear interest that ranges from 1.25 % to 2.00 % (based on the ratings of Vistra Operations' senior secured long-term debt securities), which as of December 31, 2023 was reduced to 1.70 % as a result of a sustainability pricing adjustment.

The Vistra Operations Credit Facilities also provide for certain additional customary fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit.

Effective December 20, 2023, the principal amount under the Term Loan B-3 Facility increased from $ 2.493 billion to $ 2.50 billion and bears interest based on the applicable Term SOFR Rate, plus a fixed spread of 2.00 % and the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 7.36 % under the Term Loan B-3 Facility.

Obligations under the Vistra Operations Credit Facilities are secured by liens covering substantially all of Vistra Operations' (and certain of its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities.

The Vistra Operations Credit Agreement includes certain collateral suspension provisions that would take effect upon Vistra Operations achieving unsecured investment grade ratings from two ratings agencies, there being no Term Loans (under and as defined in the Vistra Operations Credit Agreement) then outstanding (or the holders thereof agreeing to release such security interests), and there being no outstanding revolving credit commitments the maturities of which have not been extended to 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 also permit certain hedging agreements and cash management agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements and cash management agreements 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.

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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, not to exceed 5.50 to 1.00).

As of December 31, 2023, 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.

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.

In October 2022, Vistra initiated amendments 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 $ 1.35 billion.

Fees and expenses related to the facility totaled $ 6 million in the year ended December 31, 2022, which were capitalized as a reduction in the carrying amount of the debt.

Although the period ended December 31, 2022 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such time.

In October 2022, Vistra initiated amendments to the Commodity-Linked Facility to, among other things, reduce the aggregate available commitments to $ 1.35 billion.

In September 2023, the Commodity-Linked Credit Agreement was amended to (i) conform to changes and modifications consistent with the Vistra Operations Credit Agreement including to allow for the Energy Harbor acquisition and related additional financings contemplated by the Commitment Letter and (ii) give Vistra Operations the flexibility to update the deemed hedge portfolio that serves as the borrowing base under the Commodity-Linked Facility on a more frequent basis.

In October 2023, Vistra Operations initiated amendments to the Commodity-Linked Facility to, among other things,(i) extend the maturity date to October 2, 2024 and (ii) increase the aggregate available commitments to $ 1.575 billion.

Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero.

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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.

Under the Vistra Operations Commodity-Linked Credit Agreement, the interest applicable to the Commodity-Linked Facility is based on the Term SOFR Rate plus a spread that will range from 1.25 % to 2.00 %, based on the ratings of Vistra Operations' senior secured long-term debt securities, and the fee on any undrawn amounts with respect to the Commodity-Linked Facility will range from 17.5 basis points to 35.0 basis points, based on ratings of Vistra Operations' senior secured long-term debt securities.

As of December 31, 2023, the applicable interest rate margins for the Commodity-Linked Facility and the fee on any undrawn amounts with respect to the Commodity-Linked Facility were lowered to 1.70 % and 26.5 basis points, respectively, related to a sustainability pricing adjustment based on certain sustainability-linked targets and thresholds.

As of December 31, 2023, there were no outstanding borrowings under the Commodity-Linked Facility.

The Vistra Operations Commodity-Linked Credit Agreement includes a covenant, solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings exceeds 30 % of the revolving commitments), that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Commodity-Linked Facility, not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio, which is based on the ratio of consolidated total debt compared to an EBITDA calculation defined under the terms of the Commodity-Linked Facility, not to exceed 5.50 to 1.00).

As of December 31, 2023, we were in compliance with this financial covenant.

Interest Rate Swaps

Vistra employs interest rate swaps to hedge our exposure to variable rate debt.

As of December 31, 2023, Vistra has entered into the following series of interest rate swap transactions.

The rate ranges in the table below reflect the fixed leg of each swap plus an interest margin of 2.00 %.

The February 2024 and July 2026 swaps were amended in the second quarter of 2023 to reflect the conversion of LIBOR to SOFR.

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 $ 600 February 2024 3.86 % - 3.88 %

Swapped to variable $ 600 February 2024 3.35 % - 3.36 %

Swapped to fixed (a) $ 3,000 July 2026 4.72 % - 4.79 %

Swapped to variable (a) $ 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.

Swapped to fixed $ 3,000 July 2026 4.89 % - 4.97 %

Swapped to variable $ 700 July 2026 3.44 % - 3.49 %

Swapped to fixed (a) $ 1,625 December 2030 5.20 % - 5.37 %

(a) Effective from July 2026 through December 2030.

During 2019, Vistra entered into 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.

Swaps expiring in July 2026 continue to hedge our exposure on $ 2.30 billion of debt through July 2026.

In October 2023, Vistra settled and terminated $ 120 million notional amount of each series of interest rate swaps expiring in February 2024.

In March 2023, Vistra entered into $ 750 million notional amount of interest rate swaps to hedge future floating rate debt issuances.

The swaps were effective as of December 31, 2023 and expire December 31, 2030.

In December 2023, we settled the January 2024 through July 2026 mark-to-market gain of these swaps for $ 13 million in cash proceeds, amended the effective dates to July 31, 2026 and modified the fixed rate coupons to correspond with the one-month Term SOFR Rate.

In addition, in December 2023, Vistra entered into $ 875 million notional amount of interest rate swaps effective July 31, 2026 and expire December 31, 2030.

These swaps, along with the $ 750 million notional amount of interest rate swaps entered into in March 2023, will hedge our exposure on $ 1.625 billion of floating rate debt from August 2026 through December 2030.

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).

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 certain of 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.

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As of December 31, 2023, $ 788 million of letters of credit were outstanding under the Secured LOC Facilities.

Each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, not to exceed 5.50 to 1.00).

As of December 31, 2023, we were in compliance with these financial covenants.

Vistra Operations Senior Secured Notes

In September and December 2023, Vistra Operations issued $ 650 million and $ 400 million, respectively, aggregate principal amount of 6.950 % senior secured notes due 2033 ( 6.950 % Senior Secured Notes) in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

The 6.950 % 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 6.950 % Senior Secured Notes mature in October 2033, with interest payable in cash semiannually in arrears on April 15 and October 15 beginning April 2024.

Net proceeds from the September 2023 issuance totaling $ 643 million, together with proceeds from the September 2023 issuance of 7.750 % Senior Unsecured Notes discussed below and cash on hand, will be used to fund the Transactions.

Net proceeds from the December 2023 issuance totaling $ 412 million, together with proceeds from the December 2023 issuance of 7.750 % Senior Unsecured Notes discussed below and cash on hand, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the Senior Secured Notes Tender Offer described below.

In the year ended December 31, 2023, fees and expenses of $ 12 million and a debt premium of $ 9 million related to these offerings were capitalized as a reduction in the carrying amount of the debt.

In May 2022, Vistra Operations issued $ 1.5 billion aggregate principal amount of senior secured notes (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).

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Since 2019, Vistra Operations issued and sold $ 5.65 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 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 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, the 2022 Senior Secured Notes and the 6.950 % 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.

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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.

Senior Secured Notes Tender Offer — In January 2024, Vistra Operations used the net proceeds from the December 2023 issuances of 6.950 % Senior Secured Notes discussed above and 7.750 % Senior Unsecured Notes discussed below and cash on hand to fund a cash tender offer (Senior Secured Notes Tender Offer) to purchase for cash $ 759 million aggregate principal amount of certain notes, including $ 58 million of 4.875 % senior secured notes due 2024, $ 345 million of 3.550 % senior secured notes due 2024 and $ 356 million of the 5.125 % senior secured notes due 2025.

Vistra Operations Senior Unsecured Notes

In September and December 2023, Vistra Operations issued $ 1.1 billion and $ 350 million, respectively, aggregate principal amount of 7.750 % senior unsecured notes due 2031 ( 7.750 % Senior Unsecured Notes) in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

The 7.750 % Senior Unsecured 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 7.750 % Senior Unsecured Notes mature in October 2031, with interest payable in cash semiannually in arrears on April 15 and October 15 beginning April 2024.

Net proceeds from the September 2023 issuances totaling $ 1.089 billion, together with proceeds from the September 2023 issuance of 6.950 % Senior Secured Notes discussed above and cash on hand, will be used to fund the Transactions.

Net proceeds from the December 2023 issuances totaling $ 360 million, together with proceeds from the December 2023 issuance of 6.950 % Senior Secured Notes discussed above and cash on hand, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the Senior Secured Notes Tender Offer described above.

In the year ended December 31, 2023, fees and expenses of $ 17 million and a debt premium of $ 7 million related to these offerings were capitalized as a reduction in the carrying amount of the debt.

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.

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Since 2018, Vistra Operations has issued and sold $ 6.30 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 indentures governing the 5.500 % senior unsecured notes due 2026, the 5.625 % senior unsecured notes due 2027, the 5.000 % senior unsecured notes due 2027, the 4.375 % senior unsecured notes due 2029 and the 7.750 % Senior Unsecured Notes (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).

In March 2021, the Board authorized up to $ 1.8 billion to voluntarily repay or repurchase outstanding debt, which authorization expired in March 2022 (Prior Authorization).

No amounts were 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 (Current Authorization).

Through December 31, 2022, no amounts were repurchased under the Current Authorization.

Vistra Senior Unsecured Notes

On the Merger Date, Vistra assumed $ 6.138 billion principal amount of Dynegy's senior unsecured notes (Vistra Senior Unsecured Notes).

In June 2018, each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities (and did not already guarantee the senior notes) provided a guarantee on the senior notes that remained outstanding.

In January 2020, June 2020 and July 2020, Vistra redeemed aggregate principal amounts of $ 81 million of 8.000 % senior notes, $ 500 million of 5.875 % senior notes and $ 166 million of 8.125 % senior notes, respectively, at redemption prices of 104 %, 100.979 % and 104.063 %, respectively, of the aggregate principal amounts thereof, plus accrued and unpaid interest to, but excluding, the dates of redemption.

Extinguishment gains of $ 11 million were recognized on the transactions in the year ended December 31, 2020.

Vistra had no outstanding senior notes at the Parent level as of December 31, 2022 and 2021.

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.

Through December 31, 2023, no amounts were repurchased under the Updated Authorization.

Long-term debt maturities at December 31, 2023 are as follows:

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Total lease liabilities $ 291 $ 299

Cash Flows and Other Information

Supplemental Cash Flow Information

The following table presents lease related cash flows and other information:

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2023 2022 2021

Cash paid for amounts included in the measurement of lease liabilities:

Operating cash flows from operating leases $ 11 $ 11 $ 17

Operating cash flows from finance leases 8 9 5

Finance cash flows from finance leases 12 5 10

Non-cash disclosure upon commencement of new lease:

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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.

Natural Gas Index Pricing Litigation — We, through our subsidiaries, and another company remain named as defendants in one consolidated putative class action lawsuit pending in federal court in Wisconsin claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002.

The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes.

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 will be heard in the U.S.

Court of Appeals for the Seventh Circuit (Seventh Circuit Court).

In April 2023, the U.S.

Court of Appeals for the Seventh Circuit (Seventh Circuit Court) heard oral argument on an interlocutory appeal challenging the district court's order certifying a class.

Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius in July 2019.

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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.

Other parties also supported our challenge to the PUCT's orders.

In March 2023, the Third Court of Appeals issued a unanimous decision and agreed with our arguments that the PUCT's pricing orders constituted de facto competition rules and exceeded the PUCT's statutory authority.

The Third Court of Appeals vacated the pricing orders and remanded the matter to the PUCT for further proceedings.

In March 2023, the PUCT appealed the Third Court of Appeals' ruling to the Texas Supreme Court.

In September 2023, the Texas Supreme Court granted the PUC and its intervenors petitions for review of the Third Court of Appeals' decision and the Court heard oral argument in January 2024.

In 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 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 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 to $ 124 million as ERCOT collected amounts owed from certain defaulting entities through other means, primarily through securitization.

After extensive negotiations, Brazos and ERCOT reached a settlement in September 2022 that was incorporated in a proposed Brazos plan of reorganization filed with the bankruptcy court.

Under the settlement, Brazos owed two payments to ERCOT upon its emergence from bankruptcy:

first, an approximately $ 600 million payment, which ERCOT would use to replenish its Congestion Revenue Rights (CRR) 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 would 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 allows Vistra to extinguish the remaining $ 124 million default uplift liability to ERCOT on account of the Brazos short pay following confirmation of the Brazos plan of reorganization.

In September 2022, Brazos filed its plan of reorganization with the bankruptcy court and the proposed ERCOT settlement agreement was subject to the Brazos bankruptcy plan voting and confirmation processes, which concluded in November 2022 when the Brazos plan of reorganization was approved by the bankruptcy court.

In December 2022, the Brazos plan of reorganization became effective.

Accordingly, the $ 124 million default uplift liability to ERCOT, which was entirely attributable to the Brazos default, was derecognized in the fourth quarter of 2022 and recognized as revenue in the statement of operations.

We are not able to reasonably estimate the financial statement impact of a repricing as, among other things, the matter is subject to ongoing legal proceedings and, even if we were ultimately successful in the current legal proceeding, the price at which the market would be resettled is not reasonably estimable because that would be subject to further proceedings at ERCOT and the PUCT.

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, and continue to be, filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT.

In addition, a large number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been, and continue to be, filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT.

We and other defendants requested that all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL) pretrial judge.

In June 2021, the MDL panel granted the request to consolidate all these cases into a MDL for pretrial proceedings.

In June 2021, the MDL panel granted the request to consolidate all these cases into an MDL for pretrial proceedings.

Additional personal injury cases that have been, and continue to be, filed on behalf of additional plaintiffs have been consolidated with the MDL proceedings.

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In January 2023, the MDL court ruled on the various motions to dismiss and denied the motions to dismiss of the generator defendants and the transmission distribution utilities defendants, but granted the motions of some of the other defendant groups, including the retail electric providers and ERCOT.

In February 2023, the generator defendants filed a mandamus petition with the Houston Court of Appeals to review the MDL court's denial of the motion to dismiss.

In February 2023, the generator defendants filed a mandamus petition with the First Court of Appeals in Houston, Texas (First Court of Appeals) to review the MDL court's denial of the motion to dismiss.

In December 2023, the First Court of Appeals in a unanimous decision granted our mandamus petition and instructed the MDL court to grant the motions to dismiss in full filed by the generator defendants.

In January 2024, the plaintiffs filed a request with the full Court of Appeals to review that panel ruling.

We believe we have strong defenses to these lawsuits and intend to defend against these cases vigorously.

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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.

The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generation units.

In response to challenges brought by environmental groups and certain states, the U.S.

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Circuit Court issued an amended judgment, denying petitions for review of the ACE rule and challenges to the repeal of the CPP.

In addition, the EPA has opened a docket seeking input on questions related to the regulation of GHGs under Section 111(d) and has indicated its intent to issue a new proposal in Spring 2023.

In addition, the EPA opened a docket seeking input on questions related to the regulation of GHGs under Section 111(d) which closed in March 2023.

In May 2023, the EPA released a new proposal regulating power plant GHG emissions, while also proposing to repeal the ACE rule.

The new GHG proposal sets limits for (a) new natural gas-fired combustion turbines, (b) existing coal-, oil- and natural gas-fired steam generation units, and (c) certain existing natural gas-fired combustion turbines.

The proposed standards are based on technologies such as carbon capture and sequestration/storage (CCS), low-GHG hydrogen co-firing, and natural gas co-firing.

Starting in 2030, the proposal would generally require more CO 2 emissions control at fossil fuel-fired power plants that operate more frequently and for more years and would phase in increasingly stringent CO 2 requirements over time.

Under the proposal, states would be required to submit plans to the EPA within 24 months of the rule's effective date that provide for the establishment, implementation, and enforcement of standards of performance for existing sources.

These state plans must generally establish standards that are at least as stringent as the EPA's emission guidelines.

Existing steam generation units must start complying with their standards of performance on January 1, 2030.

Existing combustion turbine units must start complying with their standards of performance on January 1, 2032, or January 1, 2035, depending on their subcategory.

We submitted comments to the EPA on this proposal in August 2023.

Cross-State Air Pollution Rule (CSAPR)

In October 2015, the EPA revised the primary and secondary ozone NAAQS to lower the 8-hour standard for ozone emissions during ozone season (May to September).

In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to lower the 8-hour standard for ozone emissions during ozone season (May to September).

As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS.

In February 2023, the EPA disapproved Texas's SIP.

In April 2022, prior to the EPA's disapproval of Texas's SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS.

The proposed FIP 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 for 2023 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-fueled 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 the proposed FIP in March 2023.

In February 2022, the State of Texas, Luminant, certain trade groups, and others filed legal challenges to the EPA's disapproval of Texas's SIP in the U.S.

In February 2023, the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain trade groups, and others challenged that disapproval in the U.S.

Court of Appeals for the Fifth Circuit (Fifth Circuit Court).

If the EPA finalizes the FIP described above as expected in March 2023, it will impose reduced ozone season NO X budgets under the CSAPR program for our Texas power plants.

We cannot predict the outcome of our legal challenges to the EPA's disapproval of the SIP, any legal action related to the EPA's FIP once finalized, or the effects of the final rule (after the conclusion of legal challenges) on operations of our generation fleet.

In March 2023, those same parties filed motions to stay the EPA's SIP disapproval in the Fifth Circuit Court, and the EPA moved to transfer our challenges to the D.C.

Circuit Court or have those challenges dismissed.

In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS.

In March 2023, the EPA administrator signed its final FIP.

The FIP applies to 22 states beginning with the 2023 ozone seasons.

States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia and West Virginia.

Texas would be moved into the revised (and more restrictive) Group 3 trading program previously established in the Revised CSAPR Update Rule that includes emission budgets for 2023 that the EPA says are achievable through existing controls installed at power plants.

Allowances will be limited under the program and will be further reduced beginning in ozone season 2026 to a level that is intended to reduce operating time of coal-fueled power plants during ozone season or force coal plants to retire, particularly those that do not have selective catalytic reduction systems such as our Martin Lake power plant.

In May 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a decision on the merits and denied the EPA's motion to transfer our challenge to the D.C.

Circuit Court.

As a result of the stay, we do not believe the EPA has authority to implement the FIP as to Texas sources pending the resolution of the merits, meaning that Texas will remain in Group 2 and not be subject to any requirements under the FIP at least until the Fifth Circuit Court rules on the merits.

Oral argument was heard in December 2023 before the Fifth Circuit Court.

In June 2023, the EPA published the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the Fifth Circuit Court.

In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the FIP in the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court.

After the motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the FIP as to Texas is stayed.

In July 2023, the Fifth Circuit Court ruled that the FIP challenge would be held in abeyance pending the resolution of the litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay.

Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas

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For SO 2 , the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program.

The program includes 39 generating units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants).

The program includes 39 generation units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants).

The compliance obligations in the program started on January 1, 2019.

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We are in compliance with the rule, and the retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply.

The EPA has stated it is starting a proceeding for reconsideration of the BART rule, which we expect in 2023.

The challenges in the D.C.

Circuit Court have been held in abeyance pending the EPA's action on reconsideration.

The EPA is in the process of reconsidering the BART rule, and the challenges in the D.C.

Circuit Court have been held in abeyance pending the EPA's final action on reconsideration.

In May 2023, a proposed BART rule was published in the Federal Register that would withdraw the trading program provisions of the prior rule and would establish SO 2 limits on six facilities in Texas, including Martin Lake and Coleto Creek.

Under the current proposal, compliance would be required within 3 years for Martin Lake and 5 years for Coleto Creek.

Due to the announced shutdown for Coleto Creek, we do not anticipate any impacts at that facility, and we are evaluating potential compliance options at Martin Lake should this proposal become final.

We submitted comments to the EPA on this proposal in August 2023.

SO 2 Designations for Texas

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The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval.

In January 2024, in a split decision, the Fifth Circuit Court denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO 2 for the area around Martin Lake.

As a result of this decision, the EPA's nonattainment designation – originally made in 2016 – remains in place.

We anticipate the EPA will likely move forward with either proposing a federal plan for the area in light of an approved consent decree between the Sierra Club and the EPA that requires the EPA taking final action promulgating a FIP for the nonattainment area by December 13, 2024 or the EPA may approve Texas' SIP submittal discussed above.

In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January 2024.

Particulate Matte r

In February 2024, the EPA issued a rule addressing the annual health-based national ambient air quality standards for fine particulate matter (or PM2.5).

In general, the rule lowers the level of the annual PM2.5 standard from 12.0 micrograms per cubic meter (µg/m3) to 9.0 µg/m3.

The effective date of the rule is 60 days from publication in the Federal Register, and the earliest attainment date for areas exceeding the new standard is 2032.

At this time, we are still determining what impact, if any, this rule will have on our existing plants or any plants we may build in the future.

Based on 2020-2022 design value associated with the rule, we have just five plants (Oakland (California), Calumet (Illinois), Liberty (Pennsylvania), Miami Fort (Ohio) and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard.

We have previously announced that our Miami Fort generation facility will close by the end of 2027.

States will have to develop a plan (by late 2027 at the earliest) to get those areas into attainment and there would be a possibility that additional controls would be required for those sites.

However, before the state begins this planning process, the designation process will occur within two years from the issuance of the final rule.

The states develop recommendations about the boundaries of the nonattainment counties and the EPA must finalize the designations including the boundaries of each nonattainment area.

Effluent Limitation Guidelines (ELGs)

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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.

CCR/Groundwater

In March 2023, the EPA published its proposed supplemental ELG rule, which retains the retirement exemption from the 2020 ELG rule and sets new limits for plants that are continuing to operate.

The proposed rule also establishes pretreatment standards for combustion residual leachate, and we are currently evaluating the impact of those proposed requirements.

We submitted comments on the proposal in May 2023.

Coal Combustion Residuals (CCR)/Groundwater

In August 2018, the D.C.

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Prior to the November 2020 deadline, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios.

In 2022 and 2023, we withdrew the applications for Coffeen, Martin Lake, Joppa and Zimmer stations because extensions were no longer needed.

In November 2020, environmental groups petitioned for review of this rule in the D.C.

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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 November 2020, we submitted an application for an alternate liner demonstration for one CCR unit at Martin Lake, however, we withdrew the application for an alternate liner demonstration in November 2023 after determining the pond was no longer needed for CCR.

In August 2021, we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following the 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.

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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.

Briefing on this petition will be complete by May 2023.

Briefing before the D.C.

Circuit Court is complete and the court will hear argument in March 2024.

In May 2023, the EPA issued another proposal that further revises the federal CCR rule that would expand coverage of groundwater monitoring and closure requirements to the following two new categories of units:

(a) legacy units which are CCR impoundments at inactive sites that ceased receiving waste before October 19, 2015 and (b) so-called "CCR management units" which generally could encompass areas of CCR located at a facility that is currently regulated by the existing CCR rule.

CCR Management Units, as defined by the EPA in the proposal, could include any ash deposits, haul roads, and previously closed impoundments and landfills.

As part of the proposed rule, the EPA identified 134 CCR management units at 82 different facilities across the country, including six of our potential units.

The Vermilion ash ponds discussed below are the only unit which we believe qualify as a legacy CCR surface impoundment and given our closure plan for that site we do not believe this proposal, if finalized, will have any impact on that site.

We are continuing to evaluate what would be required of the CCR management units identified in the proposal should the proposal become final in its current form.

We submitted comments in July 2023.

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.

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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 is currently abated.

We answered that complaint in July 2021.

In July 2023, PRN filed an unopposed motion to voluntarily dismiss the case with prejudice, which the IPCB granted in August 2023 and closed the case.

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments.

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The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan.

In June 2023, the Illinois state court approved and entered the final consent order, which included the terms above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash.

These proposed closure costs are reflected in the ARO in our consolidated balance sheets (see Note 22).

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In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in January 2022 and five of our sites in July 2022.

One additional closure construction application will be filed for our Baldwin facility in 2023.

One additional closure construction application was filed for our Baldwin facility in August 2023.

For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows.

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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.

However, the CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the costs of closure methods that our operations and environmental services teams believe are appropriate based on existing closure requirements and protective of the environment for each location.

Once the IEPA acts on our permit applications, we will reassess the decommissioning costs and adjust our ARO liabilities accordingly.

MISO 2015-2016 Planning Resource Auction

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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, consistent with the FERC's scheduling orders.

In June 2023, the Company filed its initial brief and response to the remand report, and in August 2023 the Company filed a reply to the initial briefs from other parties.

We will continue to vigorously defend our position.

Other Matters

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We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by collective bargaining agreements.

The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal-, natural gas- and nuclear-fueled generation operations, as well as some battery operations, expire on various dates between March 2023 and August 2025, but remain effective thereafter unless and until terminated by either party.

The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal-, natural gas- and nuclear-fueled generation operations, as well as some battery operations, expire on various dates between March 2024 and March 2028, but remain effective thereafter unless and until terminated by either party.

While we cannot predict the outcome of labor contract negotiations, we do not expect any changes in our existing agreements to have a material adverse effect on our results of operations, liquidity or financial condition.

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The potential assessment is triggered by a nuclear liability loss in excess of $ 450 million per accident at any nuclear facility.

Effective January 1, 2024, the potential assessment is triggered by a nuclear liability loss in excess of $ 500 million per accident at any nuclear facility.

The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $ 1.06 billion of nuclear accident decontamination and reactor damage stabilization insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning.

We maintain nuclear accident decontamination and reactor damage stabilization insurance for our Comanche Peak facility in the amount of $ 2.25 billion and non-nuclear accident related property damage in the amount of $ 1.0 billion (subject to a $ 5 million deductible per accident except for natural hazards which are subject to a $ 9.5 million deductible per accident), above which we are self-insured.

We also maintain Accidental Outage insurance to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at our Comanche Peak facility are out of service for more than twelve weeks as a result of covered direct physical damage.

Such coverage provides for weekly payments per unit up to $ 4.5 million for the first 52 weeks and up to $ 3.6 million for the remaining 71 weeks.

The total maximum coverage is $ 328 million for non-nuclear property damage and $ 490 million for nuclear property damage.

We also maintain Accidental Outage insurance to help cover the additional costs of obtaining replacement electricity from another source if one or both of the units at our Comanche Peak facility are out of service for more than twelve weeks as a result of covered direct physical damage.

Such coverage provides for weekly payments per unit up to $ 4.5 million for the first 52 weeks and up to $ 3.6 million for a remaining 26 weeks for non-nuclear and 71 weeks for nuclear property damage outages.

The total maximum coverage is $ 328 million for non-nuclear property damage and $ 490 million for nuclear property damage outages.

The coverage amounts applicable to each unit will be reduced to 80 % if both units are out of service at the same time as a result of the same accident.

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Shares retired ( 3,397 ) — ( 3,397 )

Shares repurchased (b) — ( 27,988,518 ) ( 27,988,518 )

Balance at December 31, 2021 532,929,476 ( 69,031,742 ) 463,897,734

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Balance at December 31, 2023 543,635,172 ( 192,496,788 ) 351,138,384

(a) Shares issued includes share awards granted to nonemployee directors.

(b) Shares repurchased include 78,087 and 5,174,863 of unsettled shares purchased as of December 31, 2022 and 2021, respectively.

(a) Shares issued include share awards granted to nonemployee directors.

(b) Shares repurchased include 318,632 , 78,087 and 5,174,863 of unsettled shares as of December 31, 2023, 2022 and 2021, respectively.

Share Repurchase Programs

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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.

In August 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 August 2022, March 2023 and February 2024, the Board authorized incremental amounts of $ 1.25 billion, $ 1.0 billion and $ 1.5 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $ 5.75 billion.

$5.75 Billion Board Authorization

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78,470,547 $ 23.40 $ 1,836

Total repurchased through December 31, 2022 (a)

Year Ended December 31, 2023 (a)

44,994,499 27.89 1,255

Total repurchased through December 31, 2023

142,795,411 $ 24.51 $ 3,500 $ 750

January 1, 2024 through February 23, 2024 4,489,651 41.39 186

Total repurchased through February 23, 2023 106,625,552 $ 22.94 $ 2,446 $ 804

(a) Shares repurchased include 78,087 of unsettled shares repurchased for $ 2 million as of December 31, 2022.

Total repurchased through February 23, 2024 (b) 147,285,062 $ 25.03 $ 3,686 $ 2,064

(a) Shares repurchased include 318,632 of unsettled shares for $ 12 million as of December 31, 2023.

(b) Amount available for additional repurchases at the end of the period includes additional $ 1.5 billion authorization approved by the Board in February 2024.

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.

The actual timing, number and value of shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the certificates of designation of the Series A Preferred Stock, the Series B Preferred Stock and the Series C Preferred Stock, respectively.

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.

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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.

On December 29, 2023 (Series C Issuance Date), we issued 476,081 shares of Series C Preferred Stock (Series C Offering) in exchange for 74 % of outstanding TRA rights (see Note 8).

We recorded the issuance at fair value of $ 476 million.

In determining the fair value of the Series C Preferred Stock as of the issuance date, we utilized the market approach described in ASC 820, Fair Value Measurement, which considers relevant observable market information for comparable instruments and is classified as Level 2 in the fair value hierarchy.

The Series A Preferred Stock, the Series B Preferred Stock and the Series C Preferred Stock are not convertible into or exchangeable for any other securities of the Company and have limited voting rights.

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.

Common Stock Dividends — In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019.

The Series C Preferred Stock may be redeemed at the option of the Company at any time after the Series C First Reset Date (defined below) and in certain other circumstances prior to the Series C First Reset Date.

Common Stock Dividends

In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019.

Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations.

Quarterly dividends declared and paid per share of common stock for the years ended December 31, 2022, 2021 and 2020 are reflected in the table below.

Quarterly dividends paid per share of common stock for the years ended December 31, 2023, 2022 and 2021 are reflected in the table below.

Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021

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February 2023 March 2023 $ 0.198 February 2022 March 2022 $ 0.170 February 2021 March 2021 $ 0.150

May 2022 June 2022 $ 0.177 April 2021 June 2021 $ 0.150 April 2020 June 2020 $ 0.135

July 2022 September 2022 $ 0.184 July 2021 September 2021 $ 0.150 July 2020 September 2020 $ 0.135

October 2022 December 2022 $ 0.193 October 2021 December 2021 $ 0.150 October 2020 December 2020 $ 0.135

May 2023 June 2023 $ 0.204 May 2022 June 2022 $ 0.177 April 2021 June 2021 $ 0.150

August 2023 September 2023 $ 0.206 July 2022 September 2022 $ 0.184 July 2021 September 2021 $ 0.150

November 2023 December 2023 $ 0.213 October 2022 December 2022 $ 0.193 October 2021 December 2021 $ 0.150

In February 2024, the Board declared a quarterly dividend of $ 0.215 per share of common stock that will be paid in March 2024.

Preferred Stock Dividends — The annual dividend rate on each share of Series A Preferred Stock is 8.0 % from the Series A Issuance Date to, but excluding October 15, 2026 (Series A First Reset Date).

Preferred Stock Dividends

The annual dividend rate on each share of Series A Preferred Stock is 8.0 % from the Series A 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.

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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.

Semiannual dividends declared and paid per share of each respective preferred stock series for the year ended December 31, 2022 are reflected in the table below.

Dividends payable are recorded on board declaration date.

Year Ended December 31, 2022

Board Declaration Date Payment Date Per Share Amount

The annual dividend rate on each share of Series C Preferred Stock is 8.875 % from the Series C Issuance Date to, but excluding January 15, 2029 (Series C First Reset Date).

On and after the Series C First Reset Date, the dividend rate on each share of Series C Preferred Stock shall equal the five-year U.S.

Treasury rate as of the most recent reset dividend determination date (subject to a floor of 3.83 %), plus a spread of 5.045 % per annum.

The Series C Preferred Stock has a liquidation preference of $ 1,000 per share, plus accumulated but unpaid dividends.

Cumulative cash dividends on the Series C Preferred Stock are payable semiannually, in arrears, on each July 15 and January 15, commencing on July 15, 2024, when, as and if declared by the Board.

Semiannual dividends paid per share of each respective preferred stock series for the years ended December 31, 2023 and 2022 are reflected in the table below.

Dividends payable are recorded on the Board declaration date.

Year Ended December 31, 2023 Year Ended December 31, 2022

Board Declaration Date Payment

Date Per Share

Amount Board Declaration Date Payment

Date Per Share

Series A Preferred Stock:

February 2022 April 2022 $ 40.00

July 2022 October 2022 $ 40.00

Series A Preferred Stock:

February 2023 April 2023 $ 40.00 February 2022 April 2022 $ 40.00

August 2023 October 2023 $ 40.00 July 2022 October 2022 $ 40.00

Series B Preferred Stock:

May 2022 June 2022 $ 35.97

October 2022 December 2022 $ 35.00

Series B Preferred Stock:

May 2023 June 2023 $ 35.00 May 2022 June 2022 $ 35.97

November 2023 December 2023 $ 35.00 October 2022 December 2022 $ 35.00

In February 2024, the Board declared a semi-annual dividend of $ 40.00 per share of Series A Preferred Stock that will be paid in April 2024.

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As of December 31, 2023, Vistra Operations can distribute approximately $ 6.3 billion to Parent under the Vistra Operations Credit Agreement without the consent of any party.

The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $ 1.775 billion, $ 405 million and $ 1.1 billion during the years ended December 31, 2022, 2021 and 2020, respectively.

The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $ 1.625 billion, $ 1.775 billion and $ 405 million during the years ended December 31, 2023, 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.

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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.

Under the terms of the Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock, unless full cumulative dividends have been or contemporaneously are being paid or declared and a sum sufficient for the payment thereof set apart for payment on all outstanding Series A Preferred Stock (and any parity securities), Series B Preferred Stock (and any parity securities), and Series C Preferred Stock (and any parity securities), respectively, with respect to dividends through the most recent dividend payment dates, (i) no dividend may be declared or paid or set apart for payment on any junior security (other than a dividend payable solely in junior securities with respect to both dividends and the liquidation, winding-up and dissolution of our affairs), including our common stock, and (ii) we may not redeem, purchase or otherwise acquire any parity security or junior security, including our common stock, in each case subject to certain exceptions as described in the certificate of designation of the Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock, respectively.

Accumulated Other Comprehensive Income

During the years ended December 31, 2023, 2022 and 2021, we recorded changes in the funded status of our pension and other postretirement employee benefit liability totaling $ 5 million, $( 23 ) million and $( 24 ) million, respectively.

During the years ended December 31, 2022, 2021 and 2020, zero , $( 8 ) million and $( 5 ) million respectively was reclassified from accumulated other comprehensive income and reported in other deductions.

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 December 31, 2022, nine million warrants expiring in 2024 were outstanding.

The warrants were included in equity based on their fair value at the Merger Date.

During the years ended December 31, 2023, 2022 and 2021, $( 4 ) million, zero and $( 8 ) million respectively was reclassified from accumulated other comprehensive income and reported in other deductions.

At the Dynegy 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 Dynegy Merger, or 0.652 shares of Vistra common stock.

The warrants were included in equity based on their fair value at the Dynegy Merger Date.

As of December 31, 2023, total warrants outstanding was approximately nine million , and they expired in February 2024.

FAIR VALUE MEASUREMENTS

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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.

Significant unobservable inputs used in 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.

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement.

Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:

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(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 consolidated balance sheets.

(b) Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability position.

This reclassification represents the adjustment needed to reconcile to the gross amounts presented on our consolidated balance sheet.

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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.

Net asset value as a practical expedient is the classification used for assets that do not have readily determinable fair values.

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.

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Electricity purchases and sales $ 449 $ ( 1,273 ) $ ( 824 ) Income Approach Hourly price curve shape (c) $ — to $ 85 $ 44

Illiquid delivery periods for hub power prices and heat rates (d) $ 25 to $ 95 $ 60

Options — ( 483 ) ( 483 ) Option Pricing Model Gas to power correlation (e) 10 % to 100 % 56 %

Power and gas volatility (e) 5 % to 620 % 313 %

Illiquid delivery periods for hub power prices and Heat Rates (d)

$ 30 to $ 110 $ 71

Options 1 ( 237 ) ( 236 ) Option Pricing Model Natural gas to power correlation (e)

10 % to 100 % 55 %

Power and natural gas volatility (e)

10 % to 870 % 441 %

Financial transmission rights 157 ( 34 ) 123 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 85 ) to $ 25 $ ( 30 )

Natural gas 20 ( 155 ) ( 135 ) Income Approach Gas basis and illiquid delivery periods (h) $ — to $ 30 $ 13

Coal 21 ( 1 ) 20 Income Approach Probability of default (i) — % to 40 % 20 %

Recovery rate (j) — % to 40 % 20 %

Other (k) 15 ( 8 ) 7

Natural gas 9 ( 112 ) ( 103 ) Income Approach Natural gas basis (h)

$ — to $ 15 $ 6

Illiquid delivery periods (i)

$ — to $ 5 $ 4

14 ( 18 ) ( 4 )

Total $ 630 $ ( 1,674 ) $ ( 1,044 )

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Electricity purchases and sales $ 603 $ ( 1,332 ) $ ( 729 ) Income Approach Hourly price curve shape (c) $ — to $ 80 $ 38

Illiquid delivery periods for hub power prices and heat rates (d) $ 20 to $ 140 $ 80

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 %

Illiquid delivery periods for hub power prices and Heat Rates (d)

$ 25 to $ 95 $ 60

Options — ( 483 ) ( 483 ) Option Pricing Model Natural gas to power correlation (e)

10 % to 100 % 56 %

Power and natural gas volatility (e)

5 % to 620 % 313 %

Financial transmission rights 132 ( 31 ) 101 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 35 ) to $ 10 $ ( 11 )

Natural gas 29 ( 86 ) ( 57 ) Income Approach Gas basis (h) $ ( 1 ) to $ 16 $ 8

Coal 61 — 61 Income Approach Probability of default (i) — % to 40 % 20 %

Recovery rate (j) — % to 40 % 20 %

Other (k) 25 ( 3 ) 22

Natural gas 20 ( 155 ) ( 135 ) Income Approach Natural gas basis (h)

$ — to $ 30 $ 13

Total $ 791 $ ( 2,010 ) $ ( 1,219 )

(a) Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, ISO-NE, NYISO and MISO regions.

(a) Electricity purchase and sales contracts include power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO 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.

Natural gas includes swaps and forward contracts.

Options consist of physical electricity options, spread options 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 and ERCOT South and West Zone prices.

(d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability.

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(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.

(h) Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices.

(i) Primarily based on the historical forward natural gas fixed prices.

(j) Other includes contracts for coal and environmental allowances.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2023, 2022 and 2021.

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Net asset (liability) balance at beginning of period $ ( 1,219 ) $ ( 360 ) $ 22

Total unrealized valuation losses (a) ( 1,382 ) ( 53 ) ( 5 )

Purchases, issuances and settlements (b):

Total unrealized valuation losses ( 765 ) ( 1,382 ) ( 53 )

Purchases, issuances and settlements (a):

Purchases 222 185 114

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Settlements 136 345 ( 314 )

Transfers into Level 3 (c) ( 30 ) ( 2 ) ( 2 )

Transfers out of Level 3 (c) 85 ( 91 ) 57

Net change (d) ( 859 ) ( 382 ) 96

Net asset (liability) balance at end of period $ ( 1,219 ) $ ( 360 ) $ 22

Unrealized valuation gains (losses) relating to instruments held at end of period $ ( 977 ) $ ( 364 ) $ 18

(a) For the years ended December 31, 2022 and 2021, Retail segment includes unrealized net losses of $ 901 million and $ 341 million, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios in the second quarter of 2022 and the third quarter of 2021 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.

Transfers into Level 3 (b) ( 48 ) ( 30 ) ( 2 )

Transfers out of Level 3 (b) 660 85 ( 91 )

Net change (c) 175 ( 859 ) ( 382 )

Net (liability) balance at end of period $ ( 1,044 ) $ ( 1,219 ) $ ( 360 )

Unrealized valuation losses relating to instruments held at end of period $ ( 676 ) $ ( 977 ) $ ( 364 )

(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income.

Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.

(b) Includes transfers due to changes in the observability of significant inputs.

All Level 3 transfers during the periods presented are in and out of Level 2.

For the year ended December 31, 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 year ended December 31, 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.

For the year ended December 31, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable .

For the year ended December 31, 2022, transfers into Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power, natural gas, and coal derivatives where forward pricing inputs have become observable.

Substantially all changes in values of commodity contracts are reported as operating revenues in our consolidated statements of operations.

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.

We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage our exposure to commodity price and interest rate volatility.

Although we do engage in economic hedging activities to manage our exposure related to commodity price fluctuations through the use of financial and physical derivative contracts, we have no derivative positions accounted for as cash flow or fair value hedges as of December 31, 2023 and 2022.

All changes in the fair values of our derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur.

See Note 16 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.

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.

Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, fuel oil and natural gas producers, local distribution companies and energy marketing companies.

Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our 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.

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 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.

See Note 12 for details on our interest rate swaps outstanding as of December 31, 2023.

Financial Statement Effects of Derivatives

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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 years ended December 31, 2022 and 2021, net losses of $ 544 million and $ 298 million, respectively, were recognized in operating revenues due to the discontinuance of NPNS accounting on retail electric contract portfolios in the second quarter of 2022 and the third quarter of 2021 where physical settlement is no longer considered probable throughout the contract term.

These amounts are reflected in commodity contracts derivative liabilities as of December 31, 2022 and 2021.

December 31, 2023

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Net assets (liabilities) $ 5,092 $ 135 $ ( 8,240 ) $ ( 83 ) $ ( 3,096 )

As of December 31, 2022 and 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.

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Derivative (consolidated statements of operations presentation) 2023 2022 2021

Commodity contracts (Operating revenues) $ ( 4,103 ) $ ( 1,196 ) $ 241

Commodity contracts (Fuel, purchased power costs and delivery fees) 375 732 4

Interest rate swaps (Interest expense and related charges) 234 81 ( 196 )

Commodity contracts (Operating revenues) (a) $ ( 758 ) $ ( 4,103 ) $ ( 1,196 )

Commodity contracts (Fuel, purchased power costs and delivery fees) (b) ( 395 ) 375 732

Interest rate swaps (Interest expense and related charges) (c) 42 234 81

Net gain (loss) $ ( 1,111 ) $ ( 3,494 ) $ ( 383 )

(a) For the year ended December 31, 2023, includes unrealized net gains from mark-to-market valuations of commodity positions of $ 714 million.

For the years ended December 31, 2022 and 2021, includes unrealized net losses from mark-to-market valuations of commodity positions of $ 2.163 billion and $ 1.191 billion, respectively.

(b) For the years ended December 31, 2023 and 2022, includes unrealized net losses from mark-to-market valuations of commodity positions of $ 224 million and $ 347 million, respectively.

For the year ended December 31, 2021, includes unrealized net gains from mark-to-market valuations of commodity positions of $ 432 million.

(c) For the year ended December 31, 2023, includes unrealized net losses on mark-to-market valuations of interest rate swaps of $ 36 million.

For the years ended December 31, 2022 and 2021, includes unrealized gains on mark-to-market valuations of interest rate swaps of $ 250 million and $ 134 million, respectively.

Balance Sheet Presentation of Derivatives

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Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at December 31, 2022 and 2021:

The following table presents the gross notional amounts of derivative volumes by commodity, excluding those derivatives that qualified for the NPNS or other scope exceptions permitted by ASC 815, Derivatives and Hedging as of December 31, 2023 and 2022:

December 31, 2023 December 31, 2022

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Fuel oil 3 105 Million gallons

Emissions 40 18 Million tons

Emissions 24 40 Million U.S.

Renewable energy certificates 29 31 Million certificates

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(b) Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions.

Credit Risk-Related Contingent Features of Derivatives

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As of December 31, 2023, total credit risk exposure to all counterparties related to derivative contracts totaled $ 4.681 billion (including associated accounts receivable).

The net exposure to those counterparties totaled $ 1.064 billion at December 31, 2022 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure totaling $ 136 million.

The net exposure to those counterparties totaled $ 727 million at December 31, 2023 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure totaling $ 235 million.

As of December 31, 2023, the credit risk exposure to the banking and financial sector represented 80 % of the total credit risk exposure and 28 % of the net exposure.

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Amortization of unrecognized amounts, net 3 — 3 — — 5

Immediate pension and postretirement benefit cost — — 7 — — ( 1 )

Net periodic pension and OPEB cost $ 9 $ 2 $ 6 $ 5 $ 4 $ 8

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Net Actuarial Gains (Losses)

Retirement Plan — For the year ended December 31, 2022, the net actuarial gain of $ 16 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, gains attributable to actuarial assumption updates to reflect current market conditions and plan experience different than expected, partially offset by losses attributable to actual asset performance exceeding expectations and settlements.

Retirement Plan

For the year ended December 31, 2023, the net actuarial loss of $ 5 million that occurred for the pension plans during 2023 was a result of losses attributable to decreasing discount rates due to changes in the corporate bond markets and losses attributable to actuarial assumption updates to reflect current market conditions, plan experience different than expected, and settlements, partially offset by a gain attributable to actual asset performance exceeding expectations.

The Dynegy Pension Plan was amended during 2023 to extend the lump sum interest rates from calendar year 2022 through 2024 and provide in-service distributions for certain eligible employees as of December 31, 2022.

As a result, the pension obligation increased by $ 1 million and a prior service cost was created to be amortized over 2 years.

For the year ended December 31, 2022, the net actuarial gain of $ 16 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, gains attributable to actuarial assumption updates to reflect current market conditions and plan experience different than expected, partially offset by losses attributable to actual asset performance falling short of expectations and settlements.

For the year ended December 31, 2021, the net actuarial gain of $ 24 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets and gains attributable to actual asset performance exceeding expectations, partially offset by losses attributable to demographic assumption updates to reflect recent plan experience, actuarial assumption updates to reflect current market conditions, plan amendments, settlements and plan experience different than expected.

For the year ended December 31, 2020, the net actuarial loss of $ 29 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets, actuarial assumption updates to reflect current market conditions and plan amendments, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy updates, annuity purchases, lump sum windows and plan experience different than expected.

OPEB Plans — For the year ended December 31, 2022, the net actuarial gain of $ 22 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, plan experience different than expected and updates to health care assumptions, partially offset by losses attributable to actual asset performance falling short of expectations and updates to health care assumptions, partially offset by losses attributable to actual asset performance falling short of expectations.

For the year ended December 31, 2021, the net actuarial gain of $ 7 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, plan experience different than expected, updates to health care claims and trend assumptions and actual asset performance exceeding expectations, partially offset by losses attributable to demographic assumption updates and life expectancy updates.

For the period ended December 31, 2020, the net actuarial loss of $ 10 million was driven by losses attributable to decreasing discount rates due to changes in the corporate bond markets and plan experience different than expected, partially offset by gains attributable to actual asset performance exceeding expectations, life expectancy updates and updates to health care claims and trend assumptions.

For the year ended December 31, 2023, the immaterial net actuarial loss that occurred for the OPEB plans during 2023 was a result of losses attributable to decreasing discount rates due to changes in the corporate bond markets, partially offset by gains attributable to plan experience different than expected, updates to health care assumptions, and actual asset performance exceeding expectations.

For the year ended December 31, 2022, the net actuarial gain of $ 22 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, plan experience different than expected and updates to health care assumptions, partially offset by losses attributable to actual asset performance falling short of expectations.

For the period ended December 31, 2021, the net actuarial gain of $ 7 million was driven by gains attributable to increasing discount rates due to changes in the corporate bond markets, plan experience different than expected, updates to health care claims and trend assumptions and actual asset performance exceeding expectations, partially offset by losses attributable to demographic assumption updates and life expectancy updates.

Retirement Plan OPEB Plans

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Plan amendments 1 9 — —

Actuarial gain ( 113 ) ( 11 ) ( 30 ) ( 6 )

Actuarial (gain) loss 10 ( 113 ) 1 ( 30 )

Benefits paid ( 59 ) ( 73 ) ( 12 ) ( 13 )

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Funded Status:

Projected pension benefit obligation $ ( 449 ) $ ( 605 ) $ ( 110 ) $ ( 146 )

Projected benefit obligation $ ( 425 ) $ ( 449 ) $ ( 108 ) $ ( 110 )

Fair value of assets 285 320 12 29

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Net actuarial (gain) loss $ 4 $ ( 4 ) $ ( 15 ) $ ( 15 )

Prior services (credit) cost 9 — 1 1

Net loss and prior service cost $ 5 $ ( 13 ) $ ( 14 ) $ 8

Prior services cost 3 9 1 1

Net (income) loss and prior service cost $ 7 $ 5 $ ( 14 ) $ ( 14 )

Fair Value Measurement of Pension and OPEB Plan Assets

Retirement Plan — As of December 31, 2022 and 2021, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following:

Retirement Plan

As of December 31, 2023 and 2022, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following:

Asset Category:

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(b) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

OPEB Plans — As of December 31, 2022 and 2021, the Vistra OPEB plan assets measured at fair value totaled $ 29 million and $ 39 million, respectively.

(c) Consists primarily of high-yield bonds, emerging market debt, bank loans, securitized bonds and private investment grade fixed income.

As of December 31, 2023 and 2022, the Vistra OPEB plan assets measured at fair value totaled $ 12 million and $ 29 million, respectively.

At December 31, 2023 and 2022, assets consisted of $ 9 million and $ 28 million, respectively, of comingled funds valued at net asset value and $ 3 million and $ 1 million, respectively, of municipal bond and cash equivalent mutual funds classified as Level 1.

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Real estate, hedge funds and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential.

On December 30, 2022, the EEI Plan merged into the Dynegy Plan.

The target asset allocation ranges of pension plan investments by asset category are as follows:

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Vistra Plan Dynegy Plan

Fixed income 50 % - 70 % 44 % - 54 %

Fixed income securities 50 % - 70 % 40 % - 50 %

Global equity securities 20 % - 28 % 28 % - 38 %

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Assumed Health Care Cost Trend Rates-Medicare Eligible:

Health care cost trend rate assumed for next year (Vistra Plan, EEI Union and EEI Salaried) 10.30 % 9.60 %

Health care cost trend rate assumed for next year (Vistra Plan) 12.90 % 10.30 %

Health care cost trend rate assumed for next year (Split-Participant Plan) 12.30 % 10.00 %

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Contributions

Contributions to the Retirement Plan for the years ended December 31, 2022, 2021 and 2020 totaled zero , $ 1 million and $ 16 million, respectively, and no contributions are expected to be made in 2023.

OPEB plan funding for each year ended December 31, 2022, 2021 and 2020 totaled $ 9 million and funding in 2023 is expected to total $ 9 million.

Contributions to the Retirement Plan for the years ended December 31, 2023, 2022 and 2021 totaled zero , zero and $ 1 million, respectively, and contributions in 2024 are expected to total $ 14 million.

OPEB plan funding for each of the years ended December 31, 2023, 2022 and 2021 totaled $ 9 million, and funding in 2024 is expected to total $ 9 million.

Future Benefit Payments

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Vistra 2016 Omnibus Incentive Plan

On the Effective Date, the Vistra board of directors (Board) adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons.

On the Effective Date, the Board adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons.

Following approval of the Board and approval by the stockholders at the 2019 annual meeting of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000 .

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Exercisable at December 31, 2023 6,126 $ 20.01 4.2 $ 113.5

As of December 31, 2022, $ 2 million of unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 3 months.

As of December 31, 2023, there was no unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan.

Restricted Stock Units

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(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 Chief Executive Officer is our CODM.

Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations.

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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.

Substantially all of these activities are conducted by TXU Energy, Ambit, Dynegy Energy Services, Homefield Energy and U.S.

Gas & Electric across 19 states in the U.S.

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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 West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site (see Note 3).

The Sunset segment consists of generation plants with announced retirement dates after December 31, 2023.

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The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 4).

The Asset Closure segment also includes results from generation plants we retired in the year ended December 31, 2022.

The Asset Closure segment also includes results from generation plants we retired in the years ended December 31, 2023 and 2022.

Upon movement of generation plant assets to either the Sunset or Asset Closure segments, prior year results are retrospectively adjusted, if the effects are material, for comparative purposes.

Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines.

We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants retired in 2022 up until the retirement date.

We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants retired in 2022 and 2023.

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.

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Certain shared services costs are allocated to the segments.

For the year ended Retail Texas East West Sunset Asset Closure Corporate and Other (b) Eliminations Consolidated

Operating revenues (a):

For the year ended Retail Texas East West Sunset Asset Closure Corporate and Other (a)

Eliminations Consolidated

Operating revenues:

December 31, 2023 $ 10,572 $ 3,823 $ 4,215 $ 914 $ 1,831 $ — $ 2 $ ( 6,578 ) $ 14,779

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December 31, 2021 1 266 44 8 28 3 48 — 398

(a) The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:

For the year ended Retail (1) Texas East West Sunset Asset Closure Corporate and Other Eliminations (2) Consolidated

December 31, 2022 $ ( 532 ) $ ( 1,472 ) $ ( 757 ) $ ( 324 ) $ ( 3 ) $ 106 $ — $ 819 $ ( 2,163 )

December 31, 2021 ( 325 ) ( 1,272 ) ( 637 ) ( 42 ) ( 444 ) ( 190 ) — 1,719 ( 1,191 )

December 31, 2020 ( 11 ) 677 ( 23 ) ( 10 ) ( 122 ) ( 18 ) — ( 329 ) 164

(1) For the years ended December 31, 2022 and 2021, Retail segment includes unrealized net losses of $ 544 million and $ 298 million, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios in the second quarter of 2022 and the third quarter of 2021 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) 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).

(a) Income tax (expense) benefit is generally not reflected in net income (loss) of the segments but is reflected almost entirely in Corporate and Other net income (loss).

SUPPLEMENTARY FINANCIAL INFORMATION

Impairment of Long-Lived Assets

In the first quarter of 2023, we recognized an impairment loss of $ 49 million related to our Kincaid generation facility in Illinois as a result of a significant decrease in the projected operating margins of the facility, primarily driven by a decrease in projected power prices.

The impairment is reported in our Sunset segment and includes write-downs of property, plant and equipment of $ 45 million, write-downs of inventory of $ 2 million and write-downs of operating lease right-of-use assets of $ 2 million.

In the fourth quarter of 2022, we recognized an impairment loss of $ 74 million related to our Miami Fort generation facility in Ohio as a result of a significant decrease in the projected operating margins of the facility, reflecting an increase in projected coal costs along with a decrease in projected power prices.

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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.

In the third quarter of 2020, we recognized impairment losses of $ 173 million related to our Kincaid coal generation facility in Illinois and $ 99 million related to our Zimmer coal generation facility in Ohio, each as a result of a significant decrease in the estimated useful life of the facility, reflecting our recently announced plan to retire both facilities by the end of 2027 in response to the final CCR rule (see Notes 3 and 12).

The impairment for our Kincaid facility is reported in our Sunset segment and includes write-downs of property, plant and equipment of $ 166 million and write-downs of inventory of $ 7 million.

The impairment for our Zimmer facility is reported in our Asset Closure segment and includes write-downs of property, plant and equipment of $ 94 million and write-downs of inventory of $ 5 million.

In the first quarter of 2020, we recognized an impairment loss of $ 52 million related to our Joppa/EEI coal generation facility in Illinois 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 changes to the operating assumption based on lower forecasted wholesale electricity prices.

We also recorded a $ 32 million impairment to a capacity contract which was linked in part to the Joppa/EEI facility and therefore determined to have a significant decrease in estimated useful life.

The impairments are reported in our Asset Closure segment and include write-downs of property, plant and equipment of $ 45 million, write-downs of intangible assets of $ 32 million and write-downs of inventory of $ 7 million.

In determining the fair value of the impaired assets in 2022, 2021, and 2020, we utilized the income approach described in ASC 820, Fair Value Measurement and, if applicable, applied weighting to prices and other relevant information generated by market transactions involving similar assets.

In determining the fair value of the impaired asset groups in 2023, 2022, and 2021, we utilized the income approach described in ASC 820, Fair Value Measurement and, if applicable, applied weighting to prices and other relevant information generated by market transactions involving similar assets.

Interest Expense and Related Charges

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2023 2022 2021

Interest paid/accrued $ 591 $ 480 $ 467

Interest expense $ 654 $ 591 $ 480

Unrealized mark-to-market net (gains) losses on interest rate swaps 36 ( 250 ) ( 134 )

Amortization of debt issuance costs, discounts and premiums 26 28 30

Facility Fee expense 8 — —

Debt extinguishment (gain) loss ( 3 ) ( 1 ) 1

Capitalized interest ( 37 ) ( 29 ) ( 26 )

Other 29 33 28

Other (a) 56 29 33

Total interest expense and related charges $ 740 $ 368 $ 384

(a) For the year ended December 31, 2023, includes $ 21 million of fees related to the Commitment Letter (see Note 2).

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 12, was 5.69 %, 4.30 % and 3.90 % as of December 31, 2023, 2022 and 2021, respectively.

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Insurance settlements (a) $ 24 $ 70 $ 88

Gain on settlement of rail transportation disputes (b) — 15 —

Sale of land (b) 8 9 8

Gain on sale of land (b) 95 8 9

Gain on TRA settlement (c) 29 — —

Gain on settlement of rail transportation disputes (d) — — 15

Interest income 86 19 —

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Other deductions:

Loss on disposal of investment in NELP (c) $ — $ — $ 29

All other $ 14 $ 4 $ 16

Total other deductions $ 14 $ 4 $ 16

(a) For the year ended December 31, 2022, $ 62 million reported in the Texas segment, $ 6 million reported in the West segment, $ 1 million in the Asset Closure segment and $ 1 million reported in the Corporate and Other non-segment.

For the year ended December 31, 2021, $ 80 million reported in the Texas segment, $ 7 million reported in the Asset Closure segment and $ 1 million reported in the Corporate and Other non-segment.

For the year ended December 31, 2020, $ 3 million reported in the Corporate and Other non-segment, $ 2 million reported in the Asset Closure segment and $ 1 million reported in the Texas segment.

(b) Reported in the Asset Closure segment.

(a) For the year ended December 31, 2023, $ 19 million reported in the West segment and $ 5 million in the Asset Closure segment.

For the year ended December 31, 2022, $ 62 million reported in the Texas segment, $ 6 million reported in the West segment, $ 1 million reported in the Asset Closure segment and $ 1 million reported in the Corporate and Other non-segment.

For the year ended December 31, 2021, $ 80 million reported in the Texas segment, $ 7 million reported in the Sunset segment and $ 1 million reported in Corporate and Other.

(b) For the year ended December 31, 2023, $ 94 million reported in the Asset Closure segment and $ 1 million reported in the Texas segment.

For the years ended December 31, 2022 and 2021, reported in the Asset Closure segment.

(d) Reported in the Asset Closure segment.

Restricted Cash

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Total restricted cash $ 40 $ 14 $ 37 $ 33

Remediation Escrow — During the years ended December 31, 2022, 2020 and 2019, Vistra transferred asset retirement obligations related to several closed plant sites to a third-party remediation company.

As part of certain transfers, Vistra deposits funds into an escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process.

Remediation Escrow — Vistra has transferred various asset retirement obligations related to several closed plant sites to a third-party remediation company.

As part of certain transfers, Vistra deposits funds into escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process.

Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits.

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2023 2022 2021

Allowance for uncollectible accounts receivable at beginning of period (a) $ 45 $ 45 $ 42

Allowance for uncollectible accounts receivable at beginning of period $ 65 $ 45 $ 45

Increase for bad debt expense 164 179 110

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Allowance for uncollectible accounts receivable at end of period $ 61 $ 65 $ 45

(a) The beginning balance in 2020 includes a $ 6 million increase recorded due to the adoption of ASU 2016-13, Financial Instruments—Credit Losses (see Note 1).

Inventories by Major Category

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Total inventories $ 740 $ 570

Nuclear plant decommissioning trust $ 1,648 $ 1,960

Assets related to employee benefit plans (Note 16) 30 42

Nuclear decommissioning trust $ 1,951 $ 1,648

Assets related to employee benefit plans 28 30

Land investments 42 41

Miscellaneous other 14 10

Total investments $ 2,035 $ 1,729

Investment in Unconsolidated Subsidiary

On the Merger Date, we assumed Dynegy's 50 % interest in NELP, a joint venture with NextEra Energy, Inc., which indirectly owned the Bellingham NEA facility and the Sayreville facility.

In December 2019, Dynegy Northeast Generation GP, Inc.

and Dynegy Northeast Associates LP, Inc., indirect subsidiaries of Vistra, entered into a transaction agreement with NELP and certain indirect subsidiaries of NextEra Energy, Inc.

wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP in exchange for 100 % ownership interest in NJEA, the company which owns the Sayreville facility.

The NELP Transaction was approved by FERC in February 2020, and the NELP Transaction closed on March 2, 2020.

As a result of the NELP Transaction, Vistra indirectly owns 100 % of the Sayreville facility and no longer has any ownership interest in the Bellingham NEA facility.

A loss of $ 29 million was recognized in connection with the NELP Transaction, reflecting the difference between our derecognized investment in NELP and the value of our acquired 100 % interest in NJEA, which was measured in accordance with ASC 805.

The loss is reported in our consolidated statements of operations in other deductions.

Equity earnings related to our investment in NELP totaled $ 3 million for the year ended December 31, 2020, recorded in equity in earnings of unconsolidated investment in our consolidated statements of operations.

We received distributions totaling $ 3 million for the year ended December 31, 2020.

Nuclear Decommissioning Trust

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Decommissioning costs are being recovered from 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.

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 liability reported in other noncurrent liabilities and deferred credits) 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.

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The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds.

The debt securities had an average coupon rate of 2.64 % and 2.54 % as of December 31, 2022 and 2021, respectively, and an average maturity of 11 years and 10 years as of December 31, 2022 and 2021, respectively.

The debt securities had an average coupon rate of 3.19 % and 2.64 % as of December 31, 2023 and 2022, respectively, and an average maturity of 11 years as of both December 31, 2023 and 2022.

(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.

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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 December 31, 2022 and 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.

As of December 31, 2022, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $ 1.688 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 consolidated balance sheet of $ 40 million in other noncurrent assets.

As of December 31, 2023, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $ 1.742 billion, which is lower 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 liability has been recorded to our consolidated balance sheet of $ 209 million in other noncurrent liabilities and deferred credits.

The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our consolidated balance sheets, for the years ended December 31, 2023, 2022 and 2021:

Nuclear Plant Decommissioning Mining Land Reclamation Coal Ash and Other Total

Nuclear Plant Decommissioning Land Reclamation, Coal Ash and Other Total

Liability at December 31, 2020 $ 1,585 $ 851 $ 2,436

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Payments — ( 88 ) ( 88 )

Liability transfers (b) — — ( 15 ) ( 15 )

Liability at December 31, 2021 1,635 815 2,450

Accretion 53 34 87

Adjustment for change in estimates — 13 1 14

Adjustment for change in estimates (a) — 49 49

Payments — ( 88 ) ( 88 )

Liability transfers (b) — ( 61 ) ( 61 )

Liability at December 31, 2022 1,688 749 2,437

Accretion 54 34 88

Adjustment for change in estimates — 22 27 49

Adjustment for change in estimates (a) — 94 94

Payments — ( 81 ) ( 81 )

Liability transfers (b) — ( 2 ) ( 59 ) ( 61 )

Liability at December 31, 2023 1,742 796 2,538

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Noncurrent liability at December 31, 2023 $ 1,742 $ 672 $ 2,414

(a) The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in 2020.

Under applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash flows occur, and the PUCT requires a new cost estimate at least every five years.

The increase in the liability was driven by changes in assumptions including increased costs for labor, equipment and services and a delay in timing of when the U.S.

Department of Energy is estimated to begin accepting spent fuel offsite.

(a) Includes non-cash additions to asset retirement costs included in property, plant and equipment of $ 67 million, $ 19 million and $ 19 million for the years ended December 31, 2023, 2022 and 2021, respectively.

(b) Represents ARO transferred to a third-party for remediation.

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Total other noncurrent liabilities and deferred credits $ 951 $ 1,004

(a) As of December 31, 2022 and 2021, includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.

As of December 31, 2021, also includes the allocation of ERCOT default uplift charges.

See Note 12 for further discussion of the derecognition of ERCOT default uplift charges in the fourth quarter of 2022.

(b) As of December 31, 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 $ 40 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.

(a) Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.

(b) As of December 31, 2023, 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 $ 209 million in other noncurrent liabilities and deferred credits.

As of December 31, 2022, the carrying value of our ARO related to our nuclear generation plant decommissioning was higher than fair value of the assets contained in the nuclear decommissioning trust and recorded as a regulatory asset of $ 40 million in other noncurrent assets.

Fair Value of Debt

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Vistra Operations Senior Notes Level 2 11,881 11,752 9,378 8,830

Forward Capacity Agreements Level 3 — — 211 211

Equipment Financing Agreements Level 3 65 62 74 72

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 16.

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Total cash, cash equivalents and restricted cash $ 3,539 $ 525

The following summarizes our supplemental cash flow information for the years ended December 31, 2022, 2021 and 2020, respectively.

The following table summarizes our supplemental cash flow information for the years ended December 31, 2023, 2022 and 2021, respectively.

Year Ended December 31,

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Interest paid (net of capitalized interest) $ 599 $ 552 $ 456

Noncash investing and financing activities:

Non-cash investing and financing activities:

Accrued property, plant and equipment additions (a) $ 104 $ 103 $ 171

Disposition of investment in NELP $ — $ — $ 123

Acquisition of investment in NJEA $ — $ — $ 90

Book value of nuclear fuel sold $ 26 $ — $ —

(a) Represents property, plant and equipment accruals during the period for which cash has not been paid as of the end of the period.

For the years ended December 31, 2022, 2021 and 2020, we paid federal income taxes of $ 1 million, zero and zero , respectively, paid state income taxes of $ 33 million, $ 52 million and $ 40 million, respectively, received federal tax refunds of zero , zero and $ 170 million, respectively, and received state tax refunds of $ 8 million, $ 2 million and $ 10 million, respectively.

For the years ended December 31, 2023, 2022 and 2021, we paid federal income taxes of zero , $ 1 million and zero , respectively, paid state income taxes of $ 44 million, $ 33 million and $ 52 million, respectively, and received state tax refunds of $ 13 million, $ 8 million and $ 2 million, respectively.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data