What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2025-02-28 compared with 2024-02-29 · 1512 added, 1474 removed, 839 unchanged (78% of the section changed)

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

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”).

and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in equity, for each of the three years in the period ended December 31, 2024, and the related notes and the schedule listed in the Index at Item 15(b) (collectively referred to as the “financial statements”).

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.

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

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.

Critical Audit Matters

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

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

Fair Value Measurements — Certain Complex Level 3 Derivative Assets and Liabilities — Refer to Notes 1 and 12 to the financial statements

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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 appropriate application of illiquid price curves and other significant unobservable valuation inputs.

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

• We obtained the Company's complete listing of derivative assets and liabilities and related fair values as of December 31, 2024, to obtain an understanding of the types of instruments outstanding.

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

Energy Harbor Holdings LLC Acquisition — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company completed the acquisition of Energy Harbor Holdings LLC (formerly known as Energy Harbor Corp., “Energy Harbor”) for cash consideration of $3.1 billion and granting a 15% minority interest in certain Vistra businesses with a fair value estimated at $1.5 billion (collectively, the “purchase price consideration”) on March 1, 2024.

The Company accounted for the acquisition of Energy Harbor as a business combination.

Accordingly, the excess of the purchase price consideration over the identifiable assets acquired and liabilities assumed, was recorded as goodwill.

In connection with the business combination, the Company recorded $5.6 billion in property, plant and equipment, which includes the value of the three nuclear power plants.

Additionally, a portion of the purchase price consideration also included the fair value of a 15% minority interest in Vistra’s nuclear power plant.

The nuclear power plants were valued using a combination of an income approach and a market approach.

The income approach utilized a discounted cash flow analysis based upon a debt-free cash flow model.

The determination of the discounted cash flow model fair value of the nuclear plants included significant judgment and assumptions by management, including future commodity prices, earned production tax credits, anticipated production volumes, future operating costs and capital expenditures, and the discount rate applied to the nuclear plant cash flows.

Given the valuation of the nuclear power plants involved complex and subjective estimates of forecasted future growth and financial performance, performing audit procedures to evaluate the reasonableness of the valuation required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists who possess specialized skills and knowledge in modeling the fair value of long term assets.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the evaluation of the fair value of the nuclear power plants included the following, among others:

• We tested the effectiveness of internal control over the nuclear power plant valuations, including internal control related to the appropriateness of significant assumptions that are inputs to the fair value calculation and management's review of the valuation model.

• We obtained and read the third-party valuation report and evaluated the competency of the third-party specialist engaged by management to perform the valuations.

• With the assistance of our fair value specialists, we evaluated the appropriateness of management’s methodology, significant assumptions used to develop the fair value estimate, including the reasonableness of the discount cash flow model itself, the discount rate, present value factor, terminal value, and the internal rate of return, and tested the mathematical accuracy of the calculation.

• We evaluated the completeness and accuracy of the underlying data used to develop the forecasts of future cash flows, including assessing the reasonableness of the key assumptions.

/s/ Deloitte & Touche LLP

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CONSOLIDATED STATEMENTS OF OPERATIONS

(Millions of Dollars, Except Per Share Amounts)

(Millions of Dollars, Except Share Data)

Year Ended December 31,

2024 2023 2022

Operating revenues (Note 5) $ 14,779 $ 13,728 $ 12,077

Operating revenues $ 17,224 $ 14,779 $ 13,728

Fuel, purchased power costs, and delivery fees ( 7,285 ) ( 7,557 ) ( 10,401 )

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Operating income (loss) 4,081 2,661 ( 1,177 )

Other income (Note 22) 257 117 140

Other deductions (Note 22) ( 14 ) ( 4 ) ( 16 )

Interest expense and related charges (Note 22) ( 740 ) ( 368 ) ( 384 )

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

Other income 312 257 117

Other deductions ( 21 ) ( 14 ) ( 4 )

Interest expense and related charges ( 900 ) ( 740 ) ( 368 )

Impacts of Tax Receivable Agreement ( 5 ) ( 164 ) ( 128 )

Net income (loss) before income taxes 3,467 2,000 ( 1,560 )

Income tax (expense) benefit (Note 7) ( 508 ) 350 458

Income tax (expense) benefit ( 655 ) ( 508 ) 350

Net income (loss) 2,812 1,492 ( 1,210 )

Net (income) loss attributable to noncontrolling interest 1 ( 17 ) ( 10 )

Net (income) loss attributable to noncontrolling interest and redeemable noncontrolling interest ( 153 ) 1 ( 17 )

Net income (loss) attributable to Vistra 2,659 1,493 ( 1,227 )

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Diluted $ 7.00 $ 3.58 $ ( 3.26 )

See Notes to the Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

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Comprehensive income (loss) 2,826 1,491 ( 1,187 )

Comprehensive (income) loss attributable to noncontrolling interest 1 ( 17 ) ( 10 )

Comprehensive (income) loss attributable to noncontrolling interest and redeemable noncontrolling interest ( 153 ) 1 ( 17 )

Comprehensive income (loss) attributable to Vistra $ 2,673 $ 1,492 $ ( 1,204 )

See Notes to the Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Share Data)

Current assets:

Cash and cash equivalents $ 1,188 $ 3,485

Restricted cash

Trade accounts receivable — net

Income taxes receivable 8 6

Commodity and other derivative contractual assets

Margin deposits related to commodity contracts 406 1,244

Margin deposits posted under affiliate financing agreement

Prepaid expense and other current assets 515 364

Total current assets 8,119 11,637

Restricted cash

Property, plant, and equipment — net

18,173 12,432

Identifiable intangible assets — net

Commodity and other derivative contractual assets

Accumulated deferred income taxes

Other noncurrent assets 1,191 601

Total assets $ 37,770 $ 32,966

LIABILITIES AND EQUITY

Current liabilities:

Accounts receivable financing

Long-term debt due currently

Forward repurchase obligation due currently

Trade accounts payable 1,510 1,147

Commodity and other derivative contractual liabilities

Margin deposits related to commodity contracts 49 45

Accrued taxes other than income 209 203

Accrued interest 193 206

Asset retirement obligations

Other current liabilities 645 554

Total current liabilities 8,432 9,823

Margin deposits financing with affiliate

Long-term debt, less amounts due currently

15,418 12,116

Forward repurchase obligation, less amounts due currently

Commodity and other derivative contractual liabilities

Accumulated deferred income taxes

Tax Receivable Agreement obligation 14 164

Asset retirement obligations

Other noncurrent liabilities and deferred credits

Total liabilities 32,187 27,644

Commitments and Contingencies

See Notes to the Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Share Data)

Total equity:

Preferred stock ( 100,000,000 shares authorized, $ 1,000 liquidation preference per share, 2,476,066 and 2,476,081 shares outstanding at December 31, 2024 and 2023, respectively)

Common stock (par value $ 0.01 per share, 1,800,000,000 shares authorized, 339,754,307 and 351,457,016 shares outstanding at December 31, 2024 and 2023, respectively)

Treasury stock, at cost ( 208,998,299 and 192,178,156 shares at December 31, 2024 and 2023, respectively)

( 5,912 ) ( 4,662 )

Additional paid-in-capital 9,435 10,095

Accumulated deficit ( 454 ) ( 2,613 )

Accumulated other comprehensive income 20 6

Stockholders' equity 5,570 5,307

Noncontrolling interest in subsidiary 13 15

Total equity 5,583 5,322

Total liabilities and equity $ 37,770 $ 32,966

See Notes to the Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

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Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps ( 53 ) 36 ( 250 )

Unrealized net gain from nuclear decommissioning trusts ( 116 ) — —

Change in asset retirement obligation liability 38 27 13

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Impacts of Tax Receivable Agreement 5 164 128

Gain on TRA settlement ( 29 ) — —

Gain on TRA repurchase and tender offers ( 10 ) ( 29 ) —

Bad debt expense 183 164 179

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Other — net liabilities ( 111 ) ( 243 ) ( 330 )

Cash provided by (used in) operating activities 5,453 485 ( 206 )

Cash provided by operating activities 4,563 5,453 485

Cash flows — investing activities:

Capital expenditures, including nuclear fuel purchases and LTSA prepayments ( 2,078 ) ( 1,676 ) ( 1,301 )

Energy Harbor acquisition (net of cash acquired) ( 3,065 ) — —

Proceeds from sales of nuclear decommissioning trust fund securities 2,216 601 670

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Purchases of environmental allowances ( 1,226 ) ( 1,071 ) ( 1,303 )

Insurance proceeds 15 39 89

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

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

Cash used in investing activities ( 2,145 ) ( 1,239 ) ( 1,153 )

Proceeds from sales of property, plant, and equipment, including nuclear fuel 196 115 78

Proceeds from sales of transferable ITCs 150 — —

See Notes to the Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

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2024 2023 2022

Other, net ( 3 ) 10 35

Cash used in investing activities ( 5,276 ) ( 2,145 ) ( 1,239 )

Cash flows — financing activities:

Issuances of preferred stock — — 2,000

Issuances of long-term debt 3,817 2,498 1,498

Repayments/repurchases of debt ( 2,287 ) ( 33 ) ( 251 )

Borrowings under Term Loan A — — 1,250

Repayment under Term Loan A — — ( 1,250 )

Proceeds from forward capacity agreement — — 500

Net borrowings (repayments) under accounts receivable financing 750 ( 425 ) 425

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Dividends paid to preferred stockholders ( 173 ) ( 150 ) ( 151 )

Dividends paid to noncontrolling and redeemable noncontrolling interest holders ( 180 ) — —

Payment for acquisition of noncontrolling interest ( 1,748 ) — —

TRA Repurchase and tender offer — return of capital ( 122 ) — —

Other, net ( 14 ) 83 31

Cash provided by (used in) financing activities ( 294 ) ( 80 ) 2,274

Cash used in financing activities ( 1,604 ) ( 294 ) ( 80 )

Net change in cash, cash equivalents and restricted cash ( 2,317 ) 3,014 ( 834 )

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See Notes to the Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

Current assets:

Cash and cash equivalents $ 3,485 $ 455

Restricted cash (Note 22) 40 37

Trade accounts receivable — net (Note 22) 1,674 2,059

Income taxes receivable 6 27

Inventories (Note 22) 740 570

Commodity and other derivative contractual assets (Note 17) 3,645 4,538

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

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

Prepaid expense and other current assets 364 293

Total current assets 11,637 11,116

Restricted cash (Note 22) 14 33

Investments (Note 22) 2,035 1,729

Property, plant and equipment — net (Note 22) 12,432 12,554

Operating lease right-of-use assets (Note 13) 50 51

Goodwill (Note 6) 2,583 2,583

Identifiable intangible assets — net (Note 6) 1,864 1,958

Commodity and other derivative contractual assets (Note 17) 577 702

Accumulated deferred income taxes (Note 7) 1,223 1,710

Other noncurrent assets 551 351

Total assets $ 32,966 $ 32,787

LIABILITIES AND EQUITY

Current liabilities:

Short-term borrowings (Note 12) $ — $ 650

Accounts receivable financing (Note 10) — 425

Long-term debt due currently (Note 12) 2,286 38

Trade accounts payable 1,147 1,556

Commodity and other derivative contractual liabilities (Note 17) 5,258 6,610

Margin deposits related to commodity contracts 45 39

Accrued taxes other than income 203 199

Accrued interest 206 160

Asset retirement obligations (Note 22) 124 128

Operating lease liabilities (Note 13) 7 8

Other current liabilities 547 524

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

Operating lease liabilities (Note 13) 48 45

Commodity and other derivative contractual liabilities (Note 17) 1,688 1,726

Accumulated deferred income taxes (Note 7) 1 1

Tax Receivable Agreement obligation (Note 8) 164 514

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

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)

Total equity (Note 15):

Preferred stock, number of shares authorized — 100,000,000 ;

Series A (liquidation preference — $ 1,000 ;

shares outstanding:

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

Series B (liquidation preference — $ 1,000 ;

shares outstanding:

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 ;

number of shares authorized — 1,800,000,000 )

(shares outstanding:

December 31, 2023 — 351,457,016 ;

December 31, 2022 — 389,754,870 )

Treasury stock, at cost (shares:

December 31, 2023 — 192,178,156 ;

December 31, 2022 — 147,424,202 )

( 4,662 ) ( 3,395 )

Additional paid-in-capital 10,095 9,928

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

Accumulated other comprehensive income 6 7

Stockholders' equity 5,307 4,902

Noncontrolling interest in subsidiary 15 16

Total equity 5,322 4,918

Total liabilities and equity $ 32,966 $ 32,787

See Notes to the Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Millions of Dollars)

Preferred Stock Common Stock Treasury Stock Additional Paid-In Capital Retained Deficit Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity

Preferred Stock Common Stock Treasury Stock Additional Paid-In Capital Accumulated Deficit

Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity

December 31, 2021

$ 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 )

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

Effects of stock-based incentive compensation plans — — — 103 — — 103 — 103

Net income (loss) — — — — ( 1,227 ) — ( 1,227 ) 17 ( 1,210 )

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

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

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

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 )

Effects of stock-based compensation — — — 103 — — 103 — 103

Effects of stock-based incentive compensation plans — — — 168 — — 168 — 168

Net income (loss) — — — — 1,493 — 1,493 ( 1 ) 1,492

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$ 2,476 $ 5 $ ( 4,662 ) $ 10,095 $ ( 2,613 ) $ 6 $ 5,307 $ 15 $ 5,322

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

Stock repurchases ( 1,250 ) ( 1,250 ) ( 1,250 )

Effects of stock-based compensation — — — 168 — — 168 — 168

Net income (loss) — — — — 1,493 — 1,493 ( 1 ) 1,492

Effects of stock-based incentive compensation plans — — — 140 — — 140 — 140

— — — — 2,659 — 2,659 102 2,761

Dividends declared on common stock — — — — ( 307 ) — ( 307 ) — ( 307 )

Dividends declared on preferred stock — — — — ( 192 ) — ( 192 ) — ( 192 )

Dividends to noncontrolling interest — — — — — — — ( 15 ) ( 15 )

Change in accumulated other comprehensive income (loss) — — — — — 14 14 — 14

Equity issued in subsidiary to acquire Energy Harbor — — — 747 — — 747 1,560 2,307

See Notes to the Consolidated Financial Statements

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Millions of Dollars)

Preferred Stock Common Stock Treasury Stock Additional Paid-In Capital Accumulated Deficit

Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity

Modification of noncontrolling interest to redeemable noncontrolling interest (a) — — — ( 1,539 ) — — ( 1,539 ) ( 1,659 ) ( 3,198 )

Other — — — ( 8 ) ( 1 ) — ( 9 ) 10 1

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$ 2,476 $ 5 $ ( 5,912 ) $ 9,435 $ ( 454 ) $ 20 $ 5,570 $ 13 $ 5,583

(a) See Note 2 for additional information regarding activity associated with noncontrolling interest.

See Notes to the Consolidated Financial Statements

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

Vistra has six reportable segments:

(i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure.

See Note 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, 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.

As part of the 2021 regular Texas legislative sessions and in response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, the Texas legislature passed House Bill (HB) 4492 for ERCOT to obtain financing to distribute to load-serving entities (LSEs) that were uplifted and paid to ERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri.

In October 2021, the PUCT issued a Debt Obligation Order approving $ 2.1 billion financing and the methodology for allocation of proceeds to the LSEs.

In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we received $ 544 million of proceeds from ERCOT in the second quarter of 2022.

The Company accounted for the proceeds we received by analogy to the contribution model within Accounting Standards Codification (ASC) 958-605, Not-for-Profit Entities - Revenue Recognition and the grant model within International Accounting Standard 20, Accounting for Government Grants and Disclosure of Government Assistance , as a reduction to expenses in the statements of operations in the annual period for which the proceeds are intended to compensate.

We concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received were determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $ 2.1 billion funding approved in the Debt Obligation Order.

The final financial impact of Winter Storm Uri continues to be subject to the outcome of litigation arising from the event.

Recent Developments

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.

Vistra has five reportable segments:

(i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure.

See Note 19 for additional information.

Significant Accounting Policies

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

Business Combinations

The Company accounts for its business combinations in accordance with ASC 805, Business Combinations , which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value as of the acquisition date.

The excess of the purchase price over those fair values is recognized as goodwill (if any).

During the measurement period, which may be up to one year from the acquisition date, we may record adjustments to the assets acquired and liabilities assumed in the period in which they are determined.

See Note 2 for additional information.

Derivative Instruments and Mark-to-Market Accounting

We enter 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.

This recognition is referred to as mark-to-market accounting.

The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities.

We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties.

Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of derivative contracts rather than collateral.

We enter derivative instruments, including commodity contracts and interest rate swaps, to manage commodity price and interest rate risks.

All our derivatives are accounted for as economic hedges and are recorded at estimated fair value in the consolidated balance sheets with changes in fair value recorded as gains or losses in the earnings of the period in which they occur.

No derivative positions are accounted for as cash flow or fair value hedges.

When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed.

See Notes 16 and 17 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities.

A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business.

If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.

Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met.

As of December 31, 2023 and 2022, there were no derivative positions accounted for as cash flow or fair value hedges.

We report derivative instruments in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities on a gross basis without taking into consideration netting arrangements we have with counterparties.

We maintain standardized master netting agreements with certain counterparties that allow for the right to offset derivative assets and liabilities, receivables and payables on settled positions, and collateral to reduce credit exposure between us and the counterparty.

Generally, margin deposits that contractually offset derivative instruments are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral.

We report commodity hedging and trading results as revenue, fuel expense, or purchased power in the consolidated statements of operations depending on the type of activity.

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

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

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

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

See Note 11 for additional information.

Revenue Recognition

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These revenues primarily consist of physical electricity sales to the ISO/RTO, ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response available for system reliability requirements, and certain other electricity sales contracts.

See Note 5 for detailed descriptions of revenue from contracts with customers.

See Note 3 for additional information.

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

Impairment of Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist.

The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value.

If there is such impairment, a loss is recognized based on the amount by which the carrying value exceeds the fair value.

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

See Note 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.

See Note 6 for details of intangible assets with finite lives, including discussion of fair value determinations.

Goodwill and Intangible Assets with Indefinite Lives

As part of fresh start reporting and purchase accounting, reorganization value or the purchase consideration is generally allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and liabilities, then any remaining excess reorganization value or purchase consideration is allocated to goodwill.

We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist.

We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment.

See Note 6 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations.

Nuclear fuel is capitalized and reported as a component of our property, plant and equipment in our consolidated balance sheets.

Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs and delivery fees in our consolidated statements of operations.

Government Assistance

The Company qualifies for tax incentives through eligible construction spending and production through the Inflation Reduction Act of 2022 (IRA).

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

We account for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance (IAS 20).

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

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

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

See Note 4 for additional information.

Major Maintenance Costs

Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset.

Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in our consolidated statements of operations.

Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in the consolidated statements of operations.

Defined Benefit Pension Plans and OPEB Plans

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Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates.

See Note 18 for additional information regarding pension and OPEB plans.

See Note 14 for additional information.

Stock-Based Compensation

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Forfeitures are recognized as they occur.

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

See Note 18 for additional information.

Sales and Excise Taxes

Sales and excise taxes are accounted for as "pass through" items on the consolidated balance sheets with no effect on the consolidated statements of operations ( i.e.

, the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction in other current liabilities in our consolidated statements of operations).

Sales and excise taxes are accounted for as "pass through" items in the consolidated balance sheets with no effect on the consolidated statements of operations ( i.e.

Franchise and Revenue-Based Taxes

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Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt taxes, but we are not acting as an agent to collect the taxes from customers.

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

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.

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

Deferred income tax assets and liabilities are recorded to reflect, among other things, the temporary timing differences between the book basis and tax basis of assets and liabilities, as required under accounting rules.

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

As of both December 31, 2024 and 2023, deferred tax assets related to these credits totaled $ 69 million.

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

We report interest and penalties related to uncertain tax positions as current income tax expense.

Tax Receivable Agreement (TRA)

The Company accounts for its obligations under the TRA as a liability in our consolidated balance sheets (see Note 8).

The carrying value of the TRA obligation represents the discounted amount of projected payments under the TRA.

The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra operates in, including the relevant tax rate and apportionment factor for each state.

Our taxable income takes into consideration the current federal tax code and reflects our current estimates of future results of the business.

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 estimated 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.

These changes are included on our consolidated statements of operations under the heading of Impacts of Tax Receivable Agreement.

See Note 5 for additional information.

Accounting for Contingencies

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Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events.

See Note 14 for a discussion of contingencies.

See Note 15 for additional information.

Cash and Cash Equivalents

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

Restricted Cash

The terms of certain agreements require the restriction of cash for specific purposes.

See Note 22 for more details regarding restricted cash.

Property, Plant, and Equipment

Property, plant and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed (see Note 3).

Property, plant, and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed.

Significant improvements or additions to our property, plant, and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred.

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Estimated depreciable lives are based on management's estimates of the assets' economic useful lives.

See Note 6 for additional information.

Nuclear fuel is capitalized and reported as a component of our property, plant, and equipment in the consolidated balance sheets.

Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs, and delivery fees in the consolidated statements of operations.

Impairment of Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist.

The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value.

If there is such impairment, a loss is recognized based on the amount by which the carrying value exceeds the fair value.

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

See Note 6 for additional information.

Goodwill and Intangible Assets with Indefinite Lives

As part of our fresh start reporting and purchase accounting from acquisitions, reorganization value or the purchase consideration is generally allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and liabilities, then any remaining excess reorganization value or purchase consideration is allocated to goodwill.

We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist.

We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment.

See Note 7 for additional information.

Asset Retirement Obligations (ARO)

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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

The costs to ultimately decommission the Comanche Peak nuclear power plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees.

As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted for as rate regulated operations.

Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liability balance that is reflected in our consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits.

See Note 13 for additional information.

Inventories consist of materials and supplies, fuel stock and natural gas in storage.

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We expect to recover the value of inventory costs in the normal course of business.

Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets.

Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value.

See Note 22 for discussion of these and other investments.

See Note 20 for additional information.

Nuclear Decommissioning Trust (NDT) Investments and Regulatory Assets or Liability

The NRC is responsible for regulating all nuclear power plants in the U.S.

This regulatory oversight results in specific accounting considerations for nuclear plant decommissioning.

Our NDTs hold funds primarily for the ultimate decommissioning of our nuclear power plants.

Each unit has its own NDT and funds from one unit may not be used to fund decommissioning obligations of another unit.

Decommissioning costs associated with the Comanche Peak nuclear generation facility in Texas are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the NDT.

As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted for as rate regulated operations.

Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liability balance that is reflected in the consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits.

The NDTs associated with our PJM nuclear facilities have been funded with amounts collected from the previous owners and their respective utility customers.

Any shortfall of funds necessary for decommissioning the PJM nuclear facilities, determined for each generating station unit, are required to be funded by us.

Investments in the PJM NDTs are carried at fair value and gains and losses are recognized as other income or other deductions in the consolidated statements of operations.

NDTs are invested in diversified portfolios of securities generally designed to achieve a return sufficient to fund the future decommissioning work.

We retain any funds remaining in the trusts of the PJM nuclear facilities after all decommissioning has been completed.

Noncontrolling Interest and Redeemable Noncontrolling Interest in Subsidiary

A noncontrolling interest in a consolidated subsidiary represents the portion of the equity in a subsidiary not attributable, directly or indirectly, to the Company.

Noncontrolling interests are presented as a separate component of equity in the consolidated balance sheets and the presentation of net income is modified to present earnings attributed to controlling and noncontrolling interests.

Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests.

See Note 2 for additional information.

Redeemable noncontrolling interests are presented as a component of temporary equity in the mezzanine section of the consolidated balance sheet and the presentation of net income is modified to present earnings attributed to the controlling and redeemable noncontrolling interest.

In December 2024, we closed on the repurchase of the noncontrolling interest in Vistra Vision and reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation.

See Note 2 and Note 9 for additional information.

Treasury Stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in our consolidated balance sheets as a reduction to additional paid-in capital.

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in the consolidated balance sheets as a reduction to additional paid-in capital.

Treasury stock purchases made by third party brokers on our behalf are recorded on a trade date basis when we are contractually obligated to pay the broker for their repurchase costs.

See Note 16 for additional information.

At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration.

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We use our secured incremental borrowing rate based on the information available at the lease commencement date to determine the present value of lease payments.

Operating leases are included in operating lease ROU assets, operating lease liabilities (current) and operating lease liabilities (noncurrent) on our consolidated balance sheet.

Finance leases are included in property, plant and equipment, other current liabilities and other noncurrent liabilities and deferred credits on our consolidated balance sheet.

Operating leases are included in other noncurrent assets, other current liabilities, and other noncurrrent liabilities and deferred credits on the consolidated balance sheet.

Finance leases are included in property, plant, and equipment, other current liabilities and other noncurrent liabilities and deferred credits on the consolidated balance sheet.

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

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we recognize lease expense for these leases on a straight-line basis over the lease term.

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.

Adoption of Accounting Standards in 2024

Improvements to Reportable Segment Disclosures

In November 2023, the Financial Accounting Standards Board (FASB) issued ASU No.

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

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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.

The Company adopted the amendments in this ASU for its fiscal year ended December 31, 2024 which resulted in disclosure of significant segment expenses such as segment fuel, purchased power costs, and delivery fees, operating costs, and selling, general, and administrative expenses.

The amendment was applied retrospectively to all prior periods presented.

See Note 19 for additional information.

Recent Accounting Pronouncements

Improvements to Income Tax Disclosures

In December 2023, the FASB issued ASU No.

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

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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

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.

The amendments in the ASU were effective for all entities as of March 12, 2020 through December 31, 2022.

In December 2022, the FASB issued ASU 2022-06, Reference Rate Reform (Topic 848):

Deferral of the Sunset Date of Topic 848 , which deferred the sunset date of Topic 848 from December 31, 2022 to December 31, 2024.

The expedients and exceptions may be elected over time as reference rate reform activities occur through the sunset date.

We have applied the optional expedients to amendments to financial instruments that now reference the Secured Overnight Financing Rate (SOFR).

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.

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 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.

East Segment Solar Generation and Energy Storage Projects

In September 2021, we announced the planned development of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act.

Estimated commercial operation dates for these facilities range from 2024 to 2026.

As of December 31, 2023, we had accumulated approximately $ 66 million in construction-work-in-process for these East segment solar generation and battery ESS projects.

West Segment Energy Storage Projects

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 battery ESS.

Moss Landing Phase I commenced commercial operations in May 2021.

In May 2020, we announced that, subject to approval by the CPUC, we would enter into a 10 -year resource adequacy contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase II).

The CPUC approved the resource adequacy contract in August 2020.

Moss Landing Phase II commenced commercial operations in July 2021.

In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15 -year resource adequacy and energy settlement contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III).

The CPUC approved the resource adequacy and energy settlement contract in April 2022.

Moss Landing Phase III 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.

The facility was offline as we performed the work necessary to return the facility to service.

Restoration work on the facility was completed in June 2022.

Moss Landing Phases II and III were not affected by this incident.

In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the battery ESS.

A review found the root cause originated in systems separate from the battery system.

The facility was offline as we performed the work necessary to return the facility to service.

Restoration work on the facility was completed in September 2022.

Moss Landing Phases I and III were not affected by this incident.

These incidents did not have a material impact on our results of operations.

RETIREMENT OF GENERATION FACILITIES

Operational results for plants with defined retirement dates are included in our Sunset segment beginning in the quarter when a retirement plan is announced and move to the Asset Closure segment at the beginning of the calendar year the retirement is expected to occur.

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

Kincaid Kincaid, IL PJM Coal 1,108 By the end of 2027 Sunset

Miami Fort North Bend, OH PJM Coal 1,020 By the end of 2027 Sunset

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

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

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

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

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

(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.

As previously announced in April 2021, we retired the Joppa generation facilities in September 2022 in order to settle a complaint filed with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018.

As previously announced in July 2021, we retired the Zimmer coal generation facility in June 2022 due to the inability to secure capacity revenues for the plant in the PJM capacity auction held in May 2021.

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

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

Expense Disaggregation Disclosures

In November 2024, the FASB issued ASU No.

2024-03 (ASU 2024-03), Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40):

Disaggregation of Income Statement Expenses to improve disclosures by providing additional information about certain expenses in the notes to financial statements in interim and annual reporting periods.

Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement.

ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and interim periods within annual reporting periods beginning after December 15, 2027 and can be applied prospectively or retrospectively.

Early adoption is permitted.

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

Recent Developments

In January, a fire occurred at our Moss Landing 300 MW battery energy storage facility in the West segment.

We are still investigating the cause of the fire and impacts, including insurance claim recoveries, but expect to write off approximately $ 400 million of plant value to depreciation expense in the first quarter of 2025, representing the remaining net book value of the facility.

Moss Landing 300 is part of the Moss Landing complex, which includes two other battery facilities and a gas plant, with an aggregate book value of approximately $ 1 billion.

While the gas plant is operational, the other two battery facilities remain offline as we investigate the fire.

We will continue to assess if a triggering event has occurred to evaluate impairment for the other complex assets.

Energy Harbor Business Combination

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P.

(Avenue) exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15 % equity interest of Vistra Vision (collectively, Energy Harbor Merger).

The Energy Harbor Merger combined Energy Harbor's and Vistra's nuclear and retail businesses and certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free technologies (dispatchable and renewables/storage) and the retail business.

The Energy Harbor Merger was accounted for using the acquisition method in accordance with ASC 805, Business Combinations (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated fair values on the Merger Date.

The combined results of operations are reported in the consolidated financial statements beginning as of the Merger Date.

The following table summarizes the acquisition date fair value of Energy Harbor associated with the Energy Harbor Merger on the Merger Date:

Consideration

(in millions)

Cash consideration $ 3,100

15 % of the fair value of net assets contributed to Vistra Vision by Vistra (a)

Total purchase price 4,596

Fair value of noncontrolling interest in Energy Harbor (b) 811

Acquisition date fair value of Energy Harbor $ 5,407

(a) Valued using a discounted cash flow analysis of the contributed subsidiaries including contributed debt.

(b) Represents 15 % of the acquisition date fair value implied from the fair value of consideration transferred.

As a result of the Energy Harbor Merger, Vistra maintained an 85 % ownership interest in Vistra Vision and recorded the remaining 15 % equity interest as a noncontrolling interest in the consolidated balance sheets as of the Merger Date.

On the Merger Date, we reclassified the carrying value of assets contributed to Vistra Vision of $ 749 million from additional paid-in-capital of Vistra (the controlling interest) to the noncontrolling interest in subsidiary.

Provisional fair value measurements were made for acquired assets and liabilities in the first quarter of 2024 and adjustments to those measurements were made in the second, third and fourth quarters of 2024.

Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.

The provisional fair values assigned to assets acquired and liabilities assumed are as follows:

Fair Value as of

March 1, 2024

Measurement Period Adjustments recorded through December 31, 2024

(in millions)

Cash and cash equivalents $ 35 $ 5

Trade accounts receivables, inventories, prepaid expenses, and other current assets

Investments (a) 2,021 —

Property, plant, and equipment (b)

Identifiable intangible assets (c) 444 16

Commodity and other derivative contractual assets (d) 129 ( 11 )

Other noncurrent assets 61 53

Total identifiable assets acquired 8,850 65

Trade accounts payable and other current liabilities 320 57

Long-term debt, including amounts due currently 413 —

Commodity and other derivative contractual liabilities (d) 179 —

Accumulated deferred income taxes 1,314 ( 50 )

Asset retirement obligations (e) 1,368 —

Identifiable intangible liabilities 55 ( 18 )

Other noncurrent liabilities and deferred credits 18 6

Total identifiable liabilities assumed 3,667 ( 5 )

Identifiable net assets acquired 5,183 70

Goodwill (f) 224 ( 70 )

Net assets acquired $ 5,407

(a) Investments represent securities held in nuclear decommissioning trusts (NDT) for the purpose of funding the future retirement and decommissioning of the PJM nuclear generation facilities.

These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC.

They are valued using a market approach (Level 1 or Level 2 depending on security).

(b) Acquired property, plant, and equipment are valued using a combination of an income approach and a market approach.

The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).

(c) Includes acquired nuclear fuel supply contracts valued based on contractual cash flow projections over approximately five years compared with cash flows based on current market prices with the resulting difference discounted to present value (Level 3).

Also includes acquired retail customer relationships which are valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3).

(d) Acquired derivatives are valued using the methods described in Note 11 (Level 1, Level 2, or Level 3).

Contracts with terms that were not at current market prices are also valued using a discounted cash flow analysis (Level 3).

(e) Asset retirement obligations are valued using a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies (Level 3).

(f) The excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed is recorded as goodwill.

Goodwill represents expected synergies to be generated from combining operations of Energy Harbor with Vistra.

None of the Goodwill is deductible for income tax purposes.

The following unaudited pro forma financial information for the years ended December 31, 2024 and 2023 assumes that the Energy Harbor Merger occurred on January 1, 2023.

The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Energy Harbor Merger been completed on January 1, 2023, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.

Year Ended December 31,

(in millions)

Revenues $ 17,948 $ 17,148

Net income $ 2,901 $ 1,398

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Energy Harbor Merger, effects of the Energy Harbor Merger on tax expense (benefit), and other related adjustments.

Determining the amounts of revenue and earnings of Energy Harbor since the acquisition date is impractical as operations have been integrated into our commercial platform which is managed at a portfolio level.

Acquisition costs incurred in the Energy Harbor Merger totaled $ 25 million and $ 24 million for the year ended December 31, 2024 and 2023, respectively, and are classified as selling, general, and administrative expenses in the consolidated statements of operations.

Acquisition of Noncontrolling Interest

On September 18, 2024, Vistra Operations and Vistra Vision Holdings I LLC, an indirect wholly owned subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (the UPAs) with each of Nuveen and Avenue, pursuant to which Vistra Vision Holdings agreed to purchase each of Nuveen's and Avenue's combined 15 % noncontrolling interest in Vistra Vision for approximately $ 3.2 billion in cash.

The UPAs contained certain closing conditions outside our control that represent conditional redemption obligations that required us to reflect the transaction as redeemable noncontrolling interest within the mezzanine section of the consolidated balance sheet as of September 30, 2024.

The UPAs were amended prior to close to accelerate principal payments to Avenue and certain Nuveen noncontrolling interest holders.

The transaction closed on December 31, 2024 (Closing Date), with all closing conditions met.

Upon closing, we reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation.

See Note 9 for additional information.

Revenue Disaggregation

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Year Ended December 31, 2024

Retail Texas East West Sunset Asset Closure Eliminations Consolidated

Retail Texas East (a) West Asset Closure Eliminations / Corporate and Other Consolidated

(in millions)

Revenue from contracts with customers:

Retail energy charge in ERCOT $ 8,064 $ — $ — $ — $ — $ — $ 8,064

Retail energy charge in Northeast/Midwest 1,642 — — — — — — 1,642

Retail energy charge in Northeast/Midwest (a) 3,595 — — — — — 3,595

Wholesale generation revenue from ISO/RTO — 399 1,351 228 — — 1,978

Capacity revenue from ISO/RTO (a) — — 57 — 41 — — 98

Capacity revenue from ISO/RTO (b) — — 74 — — — 74

Revenue from other wholesale contracts — 422 398 230 — — 1,050

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Other revenues:

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

Affiliate sales (c) — 3,859 2,193 4 522 — ( 6,578 ) —

Transferable PTC revenues (c) — 292 264 — — — 556

Hedging revenues — realized 1,241 ( 453 ) 31 84 ( 8 ) — 895

Hedging revenue — unrealized ( 168 ) 700 143 329 9 — 1,013

Intangible amortization and other revenues 1 — ( 4 ) — — 2 ( 1 )

Intersegment sales (d) 64 4,034 3,404 6 — ( 7,508 ) —

Total other revenues 1,138 4,573 3,838 419 1 ( 7,506 ) 2,463

Total revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ ( 7,506 ) $ 17,224

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

(a) Includes ten months of revenue associated with operations acquired in the Energy Harbor Merger.

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

The East segment includes $ 126 million of capacity sold offset by $ 52 million of capacity purchased.

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

(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.

Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $ 139 million offset by $ 116 million of capacity sold within the East segment.

(d) East segment includes $ 195 million of intersegment unrealized net losses, and Texas and West segments include $ 74 million and $ 4 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

Year Ended December 31, 2023

Retail Texas East West Sunset Asset Closure Eliminations Consolidated

Retail Texas East West Asset Closure Eliminations / Corporate and Other Consolidated

(in millions)

Revenue from contracts with customers:

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Other revenues:

Intangible amortization — — 1 — ( 7 ) — — ( 6 )

Hedging and other revenues (b) 345 ( 640 ) ( 316 ) ( 291 ) ( 765 ) ( 231 ) 1 ( 1,897 )

Affiliate sales (c) — 2,572 1,686 9 484 4 ( 4,755 ) —

Transferable PTC revenues (b)

— 10 — — — — 10

Hedging revenues — realized

1,063 ( 885 ) 43 67 ( 36 ) — 252

Hedging revenue — unrealized

191 ( 714 ) 958 243 36 — 714

Intangible amortization and other revenues

2 — ( 5 ) — — 2 ( 1 )

Intersegment sales (c)

— 3,873 2,701 4 — ( 6,578 ) —

Total other revenues 1,256 2,284 3,697 314 — ( 6,576 ) 975

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The East segment includes $ 233 million of capacity sold offset by $ 135 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 $ 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.

Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $ 82 million offset by $ 73 million of capacity sold within the East segment.

(b) Represents transferable PTCs generated from qualifying solar assets during the period.

(c) East segment includes $ 814 million of intersegment unrealized net gains, and Texas and West segments include $ 48 million and $ 6 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Year Ended December 31, 2022

Retail Texas East West Sunset Asset Closure Eliminations Consolidated

Retail Texas East West Asset Closure Eliminations / Corporate and Other Consolidated

(in millions)

Revenue from contracts with customers:

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Other revenues:

Intangible amortization ( 2 ) — 74 — ( 12 ) — — 60

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

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

Hedging revenues — realized

875 ( 67 ) ( 247 ) 35 ( 333 ) 1 264

Hedging revenue — unrealized

( 532 ) ( 637 ) ( 770 ) ( 326 ) 102 — ( 2,163 )

Intangible amortization and other revenues

2 — ( 6 ) — — — ( 4 )

Intersegment sales (b)

— 2,609 2,133 9 4 ( 4,755 ) —

Total other revenues 345 1,905 1,110 ( 282 ) ( 227 ) ( 4,754 ) ( 1,903 )

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

The East segment includes $ 361 million of capacity sold offset by $ 285 million of capacity purchased.

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

(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.

Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $ 212 million offset by $ 167 million of capacity sold within the East segment.

(b) Texas and East segments include $ 780 million and $ 45 million, respectively, of intersegment unrealized net losses and West and Asset Closure segments include $ 2 million and $ 4 million respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

Retail Energy Charges

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For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.

Wholesale Generation Revenue from ISOs/RTOs

Revenue is recognized when volumes are delivered to the ISO/RTO.

Revenue is recognized over time using the output method based on kilowatt hours delivered and cash is settled within 10 days of invoicing.

Wholesale Generation Revenue from ISOs/RTOs and Revenue from Other Wholesale Contracts

Wholesale generation revenue is recognized when volumes are delivered to the ISO/RTO.

Other wholesale contracts include other revenue activity with the ISO/RTO, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers, municipalities or other wholesale counterparties.

Wholesale revenues are recognized over time using the output method based on kilowatt hours delivered or other applicable performance measurements and cash is settled shortly after invoicing.

Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely.

Wholesale generation revenues are delivered as a series of distinct services and are accounted for as a single performance obligation.

Wholesale revenues are delivered as a series of distinct services and are accounted for as a single performance obligation.

When electricity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in wholesale generation revenues.

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Capacity revenues are recognized when the performance obligation is satisfied ratably over time as our power generation facilities stand ready to deliver power to the customer.

Penalties are assessed by the ISO/RTO against generation facilities if the facility is not available during the capacity period.

The penalties are recorded as a reduction to revenue.

Revenue from Other Wholesale Contracts

Revenue is recognized when the service is performed.

Revenue is recognized over time using the output method based on kilowatt hours delivered or other applicable measurements, and cash settles shortly after invoicing.

Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely.

Other wholesale contracts are delivered as a series of distinct services and are accounted for as a single performance obligation.

Penalties are assessed by the ISO/RTO against generation facilities if the facility is not available during the capacity period and are recorded as a reduction to revenue.

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

Other Revenues

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

Revenue from derivative contracts accounted for under ASC 815, Derivatives and Hedging is not considered revenue from contracts with customers under the accounting standards related to revenue.

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.

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

Other revenues, as included in the tables of disaggregated revenue above, represent amounts not accounted for under ASC 606, Revenue from Contracts with Customers and are comprised of the following:

• Transferable production tax credit revenues accounted for as income-related grants by analogy to IAS 20 (see Note 4 for additional information).

• Intangible amortization of acquired intangible liabilities related to retail and wholesale contracts (see Note 7 for additional information).

• Hedging revenue from electricity and natural gas derivative contracts accounted for under ASC 815, Derivatives and Hedging, including the impact of realized and unrealized gains or losses on those contracts (see Note 11 for additional information).

• Intersegment sales are presented by segment and eliminated in consolidation.

Contract and Other Customer Acquisition Costs

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Practical Expedients

The vast majority of revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers.

The majority of our revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers.

Unbilled revenues are recorded based on the volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient.

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Performance Obligations

As of December 31, 2023, we have future performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers.

Therefore, an obligation exists as of the date of the results of the respective ISO/RTO capacity auction or the contract execution date.

These obligations total $ 480 million, $ 417 million, $ 282 million, $ 100 million and $ 62 million that will be recognized in the years ending December 31, 2024, 2025, 2026, 2027 and 2028, respectively, and $ 610 million thereafter.

Capacity revenues are recognized as capacity is made available to the related ISOs/RTOs or counterparties.

Accounts Receivable

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

As of December 31, 2024, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers for which the total consideration is fixed and determinable at contract execution.

Capacity revenues are recognized as the performance obligations to make capacity available to the related ISOs/RTOs or counterparties are met.

2025 2026 2027 2028 2029 2030 and Thereafter

(in millions)

Remaining performance obligations

$ 1,123 $ 825 $ 289 $ 122 $ 62 $ 548 $ 2,969

Trade Accounts Receivable

2024 December 31,

(in millions)

Wholesale and retail trade accounts receivable $ 2,061 $ 1,735

Allowance for credit losses ( 79 ) ( 61 )

Trade accounts receivable — net $ 1,982 $ 1,674

Trade accounts receivable from contracts with customers — net $ 1,514 $ 1,239

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Total trade accounts receivable — net $ 1,982 $ 1,674

GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

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.

We have selected October 1 as our annual goodwill test date.

On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2023.

Significant qualitative factors evaluated included reporting unit financial performance and market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, interest rates and changes in reporting unit book value.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:

December 31, 2023 December 31, 2022

Identifiable Intangible Asset Gross

Amount Accumulated

Amortization Net Gross

Amount Accumulated

Amortization Net

Retail customer relationship $ 2,088 $ 1,866 $ 222 $ 2,088 $ 1,768 $ 320

Software and other technology-related assets 536 315 221 475 258 217

Retail and wholesale contracts 233 217 16 233 209 24

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) 1,341 1,341

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

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

Identifiable intangible liabilities are comprised of the following:

Gross trade accounts receivable as of December 31, 2024 and December 31, 2023 include unbilled retail revenues of $ 802 million and $ 614 million, respectively.

Allowance for Credit Losses on Accounts Receivable

Year Ended December 31,

Identifiable Intangible Liability 2023 2022

Fuel and transportation purchase contracts

Other identifiable intangible liabilities — 3

Total identifiable intangible liabilities $ 131 $ 140

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,

2024 2023 2022

Retail customer relationship Depreciation and amortization 3 $ 98 $ 137 $ 197

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

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 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.

Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.

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

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.

Gas & Electric, and were determined to be indefinite-lived assets not subject to amortization.

These intangible assets are evaluated for impairment at least annually in accordance with accounting guidance related to other indefinite-lived intangible assets.

We have selected October 1 as our test date.

Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest rates.

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

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

(in millions)

Allowance for credit losses on accounts receivable at beginning of period $ 61 $ 65 $ 45

Increase for bad debt expense 183 164 179

Decrease for account write-offs ( 165 ) ( 168 ) ( 159 )

Allowance for credit losses on accounts receivable at end of period $ 79 $ 61 $ 65

GOVERNMENT ASSISTANCE

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S.

enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC, and a first-time stand-alone battery storage investment tax credit.

The section 45U nuclear PTC provides a federal tax credit of up to $15 per MWh, subject to phase out as power prices increase above $25 per MWh, to existing nuclear facilities from 2024 through 2032 subject to an annual inflation adjustment.

The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance .

Transferable PTCs

In the year ended December 31, 2024, we recognized transferable nuclear PTC revenues of $ 545 million and transferable solar PTC revenues of $ 11 million.

Our nuclear PTC revenues are an estimate based on gross receipts generated from qualifying nuclear production in 2024 and reflect our determination that we will meet the prevailing wage requirements necessary to earn the five times multiplier at all of our nuclear units.

Our computation of gross receipts includes settled spot energy revenues and capacity revenues at each nuclear unit, and excludes any hedges.

Treasury regulations are expected to further define the scope of the legislation in many important respects over the next year, including interpretive guidance on the definition of gross receipts for the nuclear PTC.

Any interpretive guidance on the definition of gross receipts which differs from the interpretation used in our estimate could result in a material change to PTC revenues attributable to 2024 and would be reflected as a change in estimate in the period in which the guidance is received.

Transferable ITCs

In June 2023, our 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III) in California commenced commercial operations.

As a result of Moss Landing Phase III meeting requirements to be placed in service in June 2023, we recognized $ 154 million of transferable ITCs associated with the project in other noncurrent assets in the consolidated balance sheet.

In September 2024, we recognized an additional $ 2 million of transferable ITCs associated with the project and reclassified the $ 156 million of credits to other current assets.

In December 2024, our Baldwin 68 MW solar / 2 MW battery ESS and Coffeen 44 MW solar / 2 MW battery ESS facilities in Illinois met requirements to be placed in service.

As a result, we recognized $ 57 million and $ 45 million of transferable ITCs associated with the projects, respectively, in other noncurrent assets in the consolidated balance sheet.

Sales of Transferable PTCs and ITCs

In October 2024, we sold $ 156 million of transferable ITCs and $ 10 million of transferable solar PTCs generated in 2023.

Vistra received cash consideration from the sale in October 2024.

In January 2025, we sold $ 200 million of transferable nuclear PTCs we recognized from qualifying 2024 nuclear production.

Cash consideration from the sale will be received in installments through July 2025 with an initial payment received in January 2025.

Vistra files a U.S.

federal income tax return that includes the results of its consolidated subsidiaries.

Vistra is the corporate parent of the Vistra consolidated group.

Vistra serves as the corporate parent of the Vistra consolidated group.

Pursuant to applicable U.S.

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2024 2023 2022

(in millions)

Federal $ 2 $ ( 1 ) $ 2

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2024 2023 2022

(in millions)

Income (loss) before income taxes $ 3,467 $ 2,000 $ ( 1,560 )

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federal statutory rate 728 420 ( 328 )

Nondeductible TRA accretion 41 18 ( 8 )

State tax, net of federal benefit 80 86 ( 19 )

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

Nondeductible TRA accretion 2 41 18

Transferable PTC revenues ( 115 ) ( 2 ) —

Equity awards ( 53 ) ( 3 ) ( 3 )

Valuation allowance ( 2 ) ( 20 ) ( 8 )

Release of Uncertain Tax Positions — ( 35 ) —

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Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2024 and 2023 are as follows:

(in millions)

Noncurrent Deferred Income Tax Assets

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Valuation allowance 75 46

Net Deferred Income Tax Asset $ 1,222 $ 1,709

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 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.

Net Deferred Income Tax Asset (Liability) $ ( 688 ) $ 1,222

As of December 31, 2024, we had total net deferred tax liabilities of approximately $ 688 million that were substantially comprised of book and tax basis differences related to our generation and mining property, plant, and equipment, partially offset by federal and state net operating loss (NOL) carryforwards.

Our net deferred tax liabilities were significantly impacted by the Energy Harbor Merger.

For the years ended December 31, 2024 and 2023, we recognized tax benefits of $ 2 million and $ 20 million primarily related to the release of the federal valuation allowance on charitable contributions and state valuation allowances, respectively.

As of December 31, 2024, we assessed the need for a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets.

We have identified negative evidence, in the form of cumulative losses on an unadjusted basis over the preceding 12 quarters.

We evaluated 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 positive and negative evidence.

We have identified positive evidence in the form of cumulative income on an unadjusted basis over the preceding 12 quarters.

We evaluated historical earnings, performed scheduling of the reversal of temporary differences, and considered other positive and negative evidence.

In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by future taxable income, and thus no valuation allowance was required.

A valuation allowance of approximately $ 3 million was recorded in the fourth quarter of 2022 against a portion of our charitable contribution deferred tax asset that is not more likely than not to be utilized before expiration in 2024.

A valuation allowance of approximately $ 30 million was recorded as part of Energy Harbor purchase accounting on state NOL carryforwards.

As of December 31, 2024, we had $ 3.2 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2031.

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

Inflation Reduction Act of 2022 (IRA)

The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax liabilities of $ 4 million and zero at December 31, 2024 and 2023, respectively.

In August 2022, the U.S.

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.

enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases.

We do not expect Vistra to be subject to the CAMT in the 2024 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess of $1 billion.

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

See Notes 1 and 4 for additional information.

Final Section 163(j) Regulations

The final Section 163(j) regulations 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 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.

The final Section 163(j) regulations, which limits qualified deductions for business interest expense, were issued in July 2020 and provided a critical correction to the proposed regulations regarding the computation of adjusted taxable income.

As of January 1, 2022, certain provisions in the final Section 163(j) regulations have sunset, including the add-back of depreciation and amortization to adjusted taxable income.

As a result, under the law as currently enacted, Vistra's deductible business interest expense was significantly limited for the 2024 tax year and will continue to be so limited under current law going forward.

Vistra remains active in legislative monitoring and advocacy efforts to support a legislative solution to reinstate and make permanent the add-back of depreciation and amortization to adjusted taxable income.

Liability for Uncertain Tax Positions

5 unchanged sentences

2024 2023 2022

(in millions)

Balance at beginning of period, excluding interest and penalties $ — $ 36 $ 38

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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.

Uncertain tax positions totaled $ 4 million and zero as of December 31, 2024 and 2023, respectively.

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

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that the action will not affect the intended tax treatment of the Spin-Off.

TAX RECEIVABLE AGREEMENT OBLIGATION

On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH.

The TRA generally provides for the payment by us to holders of TRA Rights of 85 % of the amount of cash savings, if any, in U.S.

federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.

Pursuant to the TRA, we issued 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.

Year Ended December 31,

PROPERTY, PLANT, AND EQUIPMENT

Our property, plant, and equipment consist of our power generation assets, related mining assets, land, information system hardware, capitalized corporate office lease space and other leasehold improvements.

The estimated remaining useful lives of our property, plant, and equipment ranges from 1 to 29 years.

Land is not depreciated.

(in millions)

Power generation and structures $ 22,783 $ 17,297

Office and other equipment 160 159

Total 23,546 18,028

Less accumulated depreciation ( 8,020 ) ( 6,657 )

Net of accumulated depreciation 15,526 11,371

Finance lease right-of-use assets (net of accumulated amortization) 153 160

Nuclear fuel (net of accumulated amortization of $ 409 million and $ 120 million)

Construction work in progress 1,060 522

Property, plant, and equipment — net $ 18,173 $ 12,432

Depreciation expenses totaled $ 1.670 billion, $ 1.344 billion, and $ 1.388 billion for the years ended December 31, 2024, 2023, and 2022, respectively.

Retirement of Generation Facilities

The following are all of our facilities that have either been retired, or that have announced retirement dates.

Operation results for plants with defined retirement dates are included in our Asset Closure segment at the beginning of the calendar year the retirement is expected to occur.

Facility Location ISO/RTO Fuel Type Net Generation Capacity (MW) Announced Retirement Date (a)

Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2027

Coleto Creek Goliad, TX ERCOT Coal 650 By the end of 2027 (b)

Kincaid Kincaid, IL PJM Coal 1,108 By the end of 2027 East

Miami Fort North Bend, OH PJM Coal 1,020 By the end of 2027 East

Newton Newton, IL MISO

Coal 615 By the end of 2027 East

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

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

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

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

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

(b) Following the retirement of Coleto Creek as a coal-fueled plant, the Company intends to repower it as a gas-fueled plant.

Impairment of Long-Lived Assets

In the first quarter of 2023, we recognized an impairment loss of $ 49 million related to our Kincaid generation facility in Illinois as a result of a significant decrease in the projected operating margins of the facility, primarily driven by a decrease in projected power prices.

The impairment is reported in our East segment and includes write-downs of property, plant, and equipment of $ 45 million, write-downs of inventory of $ 2 million, and write-downs of operating lease right-of-use assets of $ 2 million.

In the fourth quarter of 2022, we recognized an impairment loss of $ 74 million related to our Miami Fort generation facility in Ohio as a result of a significant decrease in the projected operating margins of the facility, reflecting an increase in projected coal costs along with a decrease in projected power prices.

The impairment is reported in our East segment and includes write-downs of property, plant, and equipment of $ 71 million and write-downs of inventory of $ 3 million.

In determining the fair value of the impaired asset groups in 2023 and 2022, we utilized the income approach described in ASC 820, Fair Value Measurement .

GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

As of December 31, 2024 and 2023, the carrying value of goodwill totaled $ 2.807 billion and $ 2.583 billion, respectively.

Retail Segment

Texas Segment

Retail Reporting Unit (a)

Texas Generation Reporting Unit

Total Goodwill

(in millions)

Balance at December 31, 2023

$ 2,461 $ 122 $ 2,583

TRA obligation at the beginning of the period $ 522 $ 395 $ 450

Accretion expense 82 64 62

Changes in tax assumptions impacting timing of payments (a) 82 64 ( 115 )

Impacts of Tax Receivable Agreement 164 128 ( 53 )

Payments ( 9 ) ( 1 ) ( 2 )

Repurchase of TRA Rights ( 506 ) — —

TRA obligation at the end of the period 171 522 395

Less amounts due currently ( 7 ) ( 8 ) ( 1 )

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

(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.

The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 21 %, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra now operates in, including the relevant tax rate and apportionment factor for each state.

Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business.

The estimates of future business results include assumptions related to renewable development projects that Vistra is planning to execute that generate significant tax benefits.

These benefits have a material impact on the timing of TRA obligation payments.

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

As of 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 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

Basic earnings per share available to common stockholders are based on the weighted average number of common shares outstanding during the period.

Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.

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

Goodwill recorded in connection with the Energy Harbor Merger (b)

Balance at December 31 2024

$ 2,461 $ 122 $ 2,807

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

(b) Allocation of goodwill attributable to the Energy Harbor acquisition to reporting units is pending completion of purchase accounting measurement period.

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

We have selected October 1 as our annual goodwill test date.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:

December 31, 2024 December 31, 2023

Identifiable Intangible Asset Gross

Amount Accumulated

Amortization Net Gross

Amount Accumulated

Amortization Net

(in millions)

Retail customer relationship $ 2,173 $ 1,977 $ 196 $ 2,088 $ 1,866 $ 222

Software and other technology-related assets 601 293 308 536 315 221

Retail and wholesale contracts 503 353 150 233 217 16

Long-term service agreements 18 5 13 18 5 13

Other identifiable intangible assets (a) 218 13 205 62 11 51

Total identifiable intangible assets subject to amortization $ 3,513 $ 2,641 872 $ 2,937 $ 2,414 523

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

Total identifiable intangible assets $ 2,213 $ 1,864

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

Identifiable intangible liabilities are comprised of the following:

Year Ended December 31,

Identifiable Intangible Liability 2024 2023

(in millions)

Long-term service agreements

Wholesale power and fuel purchase contracts

Total identifiable intangible liabilities $ 155 $ 131

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

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

2024 (weighted average in years) Year Ended December 31,

2024 2023 2022

Net income (loss) attributable to Vistra $ 1,493 $ ( 1,227 ) $ ( 1,274 )

Less cumulative dividends attributable to Series A Preferred Stock ( 80 ) ( 80 ) ( 17 )

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 )

Weighted average shares of common stock outstanding — basic 369,771,359 422,447,074 482,214,544

Net income (loss) per weighted average share of common stock outstanding — basic $ 3.63 $ ( 3.26 ) $ ( 2.69 )

Dilutive securities:

Stock-based incentive compensation plan 5,421,752 — —

Weighted average shares of common stock outstanding — diluted 375,193,110 422,447,074 482,214,544

Net income (loss) per weighted average share of common stock outstanding — diluted $ 3.58 $ ( 3.26 ) $ ( 2.69 )

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 392,218 , 8,292,647 and 14,412,299 shares for the years ended December 31, 2023, 2022 and 2021, respectively.

ACCOUNTS RECEIVABLE FINANCING

Accounts Receivable Securitization Program

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

The Receivables Facility was renewed in July 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.

RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limits described above to fund its acquisition of the Receivables from the Originators.

RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Receivables Facility.

Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings on the consolidated balance sheets.

Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our consolidated statements of cash flows.

Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers.

The Company records interest expense on amounts advanced.

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

As of December 31, 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 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 Repo Transaction).

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

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

Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the Receivables Facility.

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

(in millions)

Retail customer relationship Depreciation and amortization 2 $ 111 $ 98 $ 137

Software and other technology-related assets Depreciation and amortization 3 60 58 69

Retail and wholesale contracts Operating revenues/Fuel, purchased power costs, and delivery fees 3 ( 12 ) 8 7

Other identifiable intangible assets Fuel, purchased power costs, and delivery fees/Depreciation and amortization 4 414 357 391

Total intangible asset expense, net $ 573 $ 521 $ 604

Amounts recorded in depreciation and amortization totaled $ 173 million, $ 158 million, and $ 208 million for the years ended December 31, 2024, 2023, and 2022, respectively.

Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs, and delivery fees in the consolidated statements of operations.

Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.

The following is a description of the separately identifiable intangible assets recorded in fresh start reporting and in connection with purchase accounting from acquisitions.

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

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

The contracts were identified as either assets or liabilities based on the respective fair values utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements.

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

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

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

Gas & Electric, and were determined to be indefinite-lived assets not subject to amortization.

These intangible assets are evaluated for impairment at least annually in accordance with accounting guidance related to other indefinite-lived intangible assets.

We have selected October 1 as our test date.

Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest rates.

On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2024.

Estimated Amortization of Identifiable Intangible Assets

As of December 31, 2024, the estimated aggregate amortization expense of identifiable intangible assets, excluding environmental allowances, for each of the next five fiscal years is as shown below.

Year Estimated Amortization Expense

(in millions)

COLLATERAL FINANCING AGREEMENT WITH AFFILIATE

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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.

2 unchanged sentences

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.

As of December 31, 2024 and 2023, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $ 435 million and $ 439 million, respectively, and is reported in the consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate.

DEBT, CREDIT FACILITIES, AND FINANCINGS

Amounts in the table below represent the categories of debt obligations incurred by the Company.

(in millions)

Long-term debt, including amounts due currently:

Project-level debt

Vistra Operations debt

15,405 14,517

Long-term debt before unamortized premiums, discounts, and issuance costs

16,469 14,517

Unamortized premiums, discounts, and issuance costs

( 171 ) ( 115 )

Long-term debt including debt due currently

$ 16,298 $ 14,402

Accounts receivable financing

Forward repurchase obligation

Long-Term Debt

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

(in millions)

Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 $ 2,475 $ 2,500

BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 367 —

Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 697 —

Vistra Operations Senior Secured Notes:

2 unchanged sentences

5.125 % Senior Secured Notes, due May 13, 2025

5.050 % Senior Secured Notes, due December 30, 2026

3.700 % Senior Secured Notes, due January 30, 2027

1 unchanged sentence

6.950 % Senior Secured Notes, due October 15, 2033

6.000 % Senior Secured Notes, due April 15, 2034

5.700 % Senior Secured Notes, due December 30, 2034

Total Vistra Operations Senior Secured Notes 5,144 5,650

Energy Harbor Revenue Bonds:

3.375 % Revenue Bond, due August 1, 2029

4.750 % Revenue Bond, due June 1, 2033 and July 1, 2033

3.750 % Revenue Bond, due October 1, 2047

Total Energy Harbor Revenue Bonds

Vistra Operations Senior Unsecured Notes:

4 unchanged sentences

7.750 % Senior Unsecured Notes, due October 15, 2031

6.875 % Senior Unsecured Notes, due April 15, 2032

Total Vistra Operations Senior Unsecured Notes 7,300 6,300

3 unchanged sentences

Total long-term debt including amounts due currently 16,298 14,402

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

Less amounts due currently ( 880 ) ( 2,286 )

Total long-term debt less amounts due currently $ 15,418 $ 12,116

(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, 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 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 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 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.

• In March 2021, Vistra Operations borrowed $ 1.0 billion principal amount under the Term Loan A Facility.

In April 2021, Vistra Operations borrowed an additional $ 250 million principal amount under the Term Loan A Facility.

Proceeds from the Term Loan A Facility, together with cash on hand, were used to repay certain amounts outstanding under the Revolving Credit Facility.

Borrowings under the Term Loan A Facility were reported in short-term borrowings in our consolidated balance sheet.

In May 2021, Vistra Operations used the proceeds from the issuance of the Vistra Operations 4.375 % senior unsecured notes due 2029 (described below), together with cash on hand, to repay the $ 1.25 billion borrowings under the Term Loan A Facility.

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

Long-Term Debt Maturities

Long-term debt maturities at December 31, 2024 are as follows:

December 31, 2024

(in millions)

Thereafter 8,161

Unamortized premiums, discounts, and debt issuance costs ( 171 )

Total long-term debt, including amounts due currently $ 16,298

Credit Facilities

Our credit facilities and related available capacity at December 31, 2024 are presented below.

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Credit Facilities Maturity Date Facility

Borrowings Letters of Credit Outstanding Available

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

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

(Long-Term Debt, Including Amounts Due Currently)

Letters of Credit Outstanding Available

(in millions)

Vistra Operations debt:

Revolving Credit Facility October 11, 2029 $ 3,440 $ — $ 1,278 $ 2,162

Term Loan B-3 Facility December 20, 2030 2,475 2,475 — —

Total Vistra Operations Credit Facilities $ 5,915 $ 2,475 $ 1,278 $ 2,162

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

Vistra Operations Commodity-Linked Facility October 1, 2025 1,750 — — 771

Total Vistra Operations debt $ 7,665 $ 2,475 $ 1,278 $ 2,933

Project-level debt:

Tax Credit Bridge Loan November 1, 2025 106 106 — —

Tax Credit Bridge Loan December 3, 2026 261 261 — —

BCOP Credit Facility 367 367 — —

Vistra Zero Term Loan B Facility (a) April 30, 2031 697 697 — —

Total project-level debt $ 1,064 $ 1,064 $ — $ —

Total credit facilities $ 8,729 $ 3,539 $ 1,278 $ 2,933

(a) 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.

The full amount of Extended Revolving Credit Facility available capacity can be utilized to issue letters of credit.

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

(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.

(a) Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries.

Vistra Operations Credit Facilities

Vistra maintains credit facilities with certain financial institutions and, as of December 31, 2024, has aggregate commitments of up to $ 5.915 billion in senior secured, first-lien revolving credit commitments and outstanding term loans (Vistra Operations Credit Facilities).

The Vistra Operations Credit Facilities consist of (i) revolving credit commitments of up to $ 3.440 billion, including aggregate revolving letter of credit commitments of up to $ 3.440 billion (Revolving Credit Facility), and (ii) term loans of $ 2.475 billion (Term Loan B-3 Facility).

These amounts reflect the following transactions and amendments completed in 2024:

Amendment Date

December 2024

Lowered fixed spread on Term Loan B-3 Facility borrowings from 2.00 % to 1.75 %

Increased Revolving Credit Facility commitments from $ 3.175 billion to $ 3.440 billion

Extended the maturity date of the Revolving Credit Facility to October 11, 2029

Revolving Credit Facility — The Revolving Credit Facility is used for general corporate purposes.

Under the Vistra Operations Credit Agreement, the interest on borrowings under the Revolving Credit Facility is paid based on (i) the forward-looking term rate based on SOFR (Term SOFR) plus a spread that will range from 1.25 % to 2.00 % and (ii) the fee on any undrawn amounts with respect to the Revolving Credit Facility ranges from 17.5 basis points to 35.0 basis points.

Interest periods for Term SOFR borrowings are for a one-, three-, or six-month periods with interest paid in arrears.

Letters of credit issued under the Revolving Credit Facility bear interest that ranges from 1.25 % to 2.00 % and are paid quarterly in arrears.

Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt securities.

As of December 31, 2024, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 1.725 % and 27.0 basis points, respectively, and the applicable interest rate margin for the letters of credit issued under the Revolving Credit Facility was 1.725 %.

Term Loan B-3 Facility — The Term Loan B-3 Facility is used for general corporate purposes and bears interest based on the applicable Term SOFR, plus a fixed spread of 2.00 % through December 9, 2024 and 1.75 % thereafter, and the weighted average interest rates before taking into consideration interest rate swaps (see Note 11) on outstanding borrowings of $ 2.475 billion was 6.11 % as of December 31, 2024.

Interest periods for Term SOFR loans are for a one-, three-, or six-month periods with interest paid in arrears.

Cash borrowings under the Term Loan B-3 Facility are subject to required scheduled quarterly payments of $ 6.25 million.

Amounts paid cannot be reborrowed.

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 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 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.

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

Such collateral suspension provisions would continue to be in effect unless and until Vistra Operations no longer holds unsecured investment grade ratings from at least two ratings agencies, at which point collateral reversion provisions would take effect (subject to a 60 -day grace period).

The Vistra Operations Credit Facilities also permit certain hedging agreements and cash management agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements and cash management agreements meet certain criteria set forth in the Vistra Operations Credit Facilities.

The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agent under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Facilities.

The Vistra Operations Credit Agreement also includes a springing financial covenant with respect to the Revolving Credit Facility that, when applicable, would require compliance with a consolidated first lien net leverage ratio.

Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.

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, the consolidated total net leverage ratio, which is based on the ratio of consolidated total debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 5.50 to 1.00).

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

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest, or fees when due, material breaches of representations and warranties, breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the existence of material unpaid (or unstayed) judgments against Vistra Operations and certain of its subsidiaries.

Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

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, 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.

The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder.

As of December 31, 2024, Vistra Operations can distribute approximately $ 8.2 billion to Parent under the Vistra Operations Credit Agreement without the consent of any party.

The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $ 1.705 billion, $ 1.625 billion, and $ 1.775 billion during the years ended December 31, 2024, 2023, and 2022, respectively.

Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to pay any taxes or general operating or corporate overhead expenses arising out of Parent's ownership or operation of Vistra Operations.

As of December 31, 2024, all of the restricted net assets of Vistra Operations may be distributed to Parent.

Vistra Operations Commodity-Linked Revolving Credit Facility

As of December 31, 2024, Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) totaled $ 1.75 billion of aggregate available commitments.

We have the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility to $ 3.0 billion.

As of December 31, 2024, the borrowing base of $ 771 million is lower than the facility limit which represents the aggregate commitments of $ 1.75 billion.

These amounts reflect the following amendment completed in 2024:

Amendment Date

Increased the aggregate available commitments to $ 1.75 billion

Extended the maturity date to October 1, 2025

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

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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.

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 $ 600 February 2024 3.86 % - 3.88 %

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

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.

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 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.

In October 2021, September 2022 and October 2022, Vistra entered into additional Secured LOC Facilities which are used for general corporate purposes.

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, the consolidated total net leverage ratio not to exceed 5.50 to 1.00).

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

Interest on the Commodity-Linked Facility bears interest (i) based on either the Term SOFR or a daily simple SOFR rate, (ii) a spread that ranges from 1.25 % to 2.00 %, and (iii) sustainability pricing adjustments based on certain sustainability-linked targets and thresholds.

Interest periods for Term SOFR borrowings are for a one-, three-, or six-month periods with interest paid in arrears.

The interest period for a daily simple SOFR is for a one-week period with interest paid in arrears.

The fee on any undrawn amounts with respect to the Commodity-Linked Facility ranges from 17.5 basis points to 35.0 basis points.

As of December 31, 2024, the applicable interest rate margins for borrowings outstanding under the Commodity-Linked Facility was 1.725 % and the fee on any undrawn amounts with respect to the Commodity-Linked Facility was 27.0 basis points.

Interest and fees on the Commodity-Linked Facility are based on ratings of Vistra Operations' senior secured long-term debt securities.

BCOP Project-level Credit Facilities

In December 2024, BCOP and its subsidiaries entered into the BCOP Credit Agreement to fund the development of the Baldwin and Coffeen solar generation and battery ESS facilities and the Oak Hill and Pulaski solar generation facilities in Illinois and Texas.

The BCOP Credit Agreement provides for (i) tax credit bridge loans of $ 367 million for the Oak Hill and Pulaski projects (Tax Credit Bridge Loans) and (ii) construction/term loan commitments of $ 528 million and debt service reserve letter of credit facility commitments of $ 29 million for all four facilities.

At December 31, 2024, the Tax Credit Bridge Loans for Oak Hill and Pulaski totaled $ 106 million and $ 261 million, respectively, and mature in November 2025 and December 2026, respectively, subject to the terms of the BCOP Credit Agreement.

The weighted average interest rate on outstanding borrowings was 5.984 % at December 31, 2024.

Repayment of the Tax Credit Bridge Loans are guaranteed by Vistra as the beneficiary of the underlying investment tax credits to be generated by the projects.

At December 31, 2024, there were no construction/term loan borrowings outstanding or debt service reserve letters of credit issued.

Interest is paid on the Tax Credit Bridge Loan in arrears based on the applicable Term SOFR rate elected in the borrowing notice plus a fixed spread of 1.625 % per annum.

Interest on the construction/term loans will be paid in arrears based on the applicable Term SOFR rate elected in the borrowing notice plus fixed spreads of 1.875 % per annum for construction loans and 2.000 % per annum for term loans.

Fees on the debt service reserve letter of credit loans will be paid in arrears at 2.000 % per annum.

Commitment fees on the undrawn loan commitments and unissued letter of credit commitments will pay quarterly in arrears at a fixed percentage of the loan's fixed spread.

Vistra Zero Project-level Credit Agreement

In March 2024, Vistra Zero Operations entered into the Vistra Zero Credit Agreement.

The Vistra Zero Credit Agreement provides for a senior secured term loan (Term Loan B Facility) of up to $ 700 million, which Vistra Zero Operations borrowed in its entirety in March 2024.

Net proceeds of $ 690 million were used (i) to pay issuance costs and (ii) for working capital and general corporate purposes.

Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries.

These amounts reflect the following amendment completed in 2024:

Amendment Date

December 2024

Lowered the fixed spread interest applicable to the Term Loan B Facility from 2.75 % to 2.00 %

Removed required scheduled quarterly payment requirements

Interest on the Term Loan B Facility is based on Term SOFR plus 2.75 % per year through December 16, 2024.

The December 2024 amendment lowered the fixed spread on this instrument to 2.00 % thereafter.

Interest periods for Term SOFR loans are for a one-, three-, or six-month periods with interest paid in arrears.

The weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings of $ 697 million was 6.36 % as of December 31, 2024.

The Vistra Zero Credit Agreement contains customary covenants and warranties which are generally consistent in scope with the Vistra Operations Credit Agreement, except that there is no financial maintenance covenant in the Vistra Zero Credit Agreement.

Letter of Credit Facilities

Vistra Operations Secured Letter of Credit Facilities

Between August 2020 and July 2024, we entered into uncommitted standby letter of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities).

The Secured LOC Facilities are secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities).

The Secured LOC Facilities may be renewed annually and are used for general corporate purposes.

As of December 31, 2024, $ 1.157 billion of letters of credit were outstanding under the Secured LOC Facilities.

Vistra Operations Unsecured Alternative Letter of Credit Facilities

In March 2024, we entered into unsecured alternative letter of credit facilities (Alternative LOC Facilities) to be used for general corporate purposes.

In May 2024, the Alternative LOC Facilities were amended to increase the commitment cap to a total of $ 500 million.

As of December 31, 2024, the total capacity was $ 500 million and $ 500 million of letters of credit were outstanding under the Alternative LOC Facilities.

The commitments under the Alternative LOC Facilities terminate in December 2028.

There are no financial maintenance covenants in the Alternative LOC Facilities.

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).

The 2022 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers.

The 4.875 % Senior Secured Notes mature in May 2024 and the 5.125 % Senior Secured Notes mature in May 2025.

Interest on the 2022 Senior Secured Notes is payable in cash semiannually in arrears on May 13 and November 13 of each year, beginning in November 2022.

Net proceeds from the Senior Secured Notes Offering totaling $ 1.485 billion, together with cash on hand, were used to pay down borrowings under the Commodity-Linked Facility.

Fees and expenses related to the offering totaled $ 17 million in the year ended December 31, 2023, which were capitalized as a reduction in the carrying amount of the debt.

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, 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.

The collateral securing the Senior Secured Notes will be released if Vistra Operations' senior, unsecured long-term debt securities obtain an investment grade rating from two out of the three rating agencies, subject to reversion if such rating agencies withdraw the investment grade rating of Vistra Operations' senior, unsecured long-term debt securities or downgrade such rating below investment grade.

The Vistra Operations Senior Secured Indenture contains certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

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 issues and sells its senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Secured Notes).

The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the Senior Secured Notes provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities.

In December 2024, Vistra Operations issued $ 1.25 billion aggregate principal amount of senior secured notes, consisting of $ 500 million aggregate principal amount of 5.050 % senior secured notes due 2026 ( 5.050 % Senior Secured Notes) and $ 750 million aggregate principal amount of 5.700 % senior secured notes due 2034 ( 5.700 % Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

Interest is payable in cash semiannually in arrears on June 30 and December 30 beginning June 30, 2025.

Net proceeds totaling approximately $ 1.240 billion, together with cash on hand, will be used for (i) general corporate purposes, including to refinance outstanding indebtedness (including 2025 debt maturities), (ii) to fund the opportunistic early payout of the purchase price installment payments scheduled to be paid in 2025 and 2026 to Avenue for the acquisition of the noncontrolling interest in Vistra Vision and (iii) to pay fees and expenses related to the offering.

In May 2024 and July 2024, the 4.875 % senior secured notes due May 2024 and 3.550 % senior secured notes due July 2024, respectively, were repaid at maturity.

In April 2024, Vistra Operations issued $ 500 million aggregate principal amount of 6.000 % senior secured notes due 2034 ( 6.000 % Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024.

Net proceeds totaling approximately $ 495 million, together with proceeds from the April 2024 issuance of 6.875 % Senior Unsecured Notes discussed below and cash on hand, were to be used for general corporate purposes, including to refinance outstanding indebtedness (the senior secured debt maturities in May 2024 and July 2024).

Energy Harbor Revenue Bonds

Various governmental entities in Ohio and Pennsylvania have issued multiple tranches of revenue bonds for the benefit of Energy Harbor Generation LLC (EHG) or Energy Harbor Nuclear Generation LLC (EHNG);

(collectively, the EH entities), in an aggregate principal amount of $ 431 million.

The relevant EH entity is obligated to provide contractual payments to the applicable issuer of the revenue bonds to service the principal and interest on the revenue bonds, the payment of which is indirectly secured by all or substantially all of the assets of the EH entities under various mortgage bonds issued by the EH entities.

In the event of a default by the EH entities of their contractual obligation to pay principal and interest in respect of the revenue bonds, the trustee of the revenue bonds would be able to call the mortgage bonds due and, if unpaid, foreclose on the assets securing the mortgage bonds.

The obligations of the EH entities in respect of the revenue bonds and related mortgage bonds are guaranteed on an unsecured basis by Energy Harbor and Vistra.

Vistra Operations Senior Unsecured Notes

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.

The 4.375 % senior unsecured notes due 2029 were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P.

Morgan Securities LLC, as representative of the several initial purchasers.

The 4.375 % senior unsecured notes mature in May 2029, with interest payable in arrears on May 1 and November 1 beginning November 1, 2021 with interest accrued from May 10, 2021.

Net proceeds, together with cash on hand, were used to repay all amounts outstanding under the Term Loan A Facility and to pay fees and expenses of $ 15 million related to the offering.

Fees and expenses were capitalized as a reduction in the carrying amount of the debt.

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, 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.

Vistra Operations issues and sells its senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Unsecured Notes).

The indentures (as may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) governing the Senior Unsecured Notes provide for the full and unconditional guarantee by the Guarantor Subsidiaries.

The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

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 (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 (Updated Authorization).

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

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

In April 2024, Vistra Operations issued $ 1.0 billion aggregate principal amount of 6.875 % senior unsecured notes due 2032 ( 6.875 % Senior Unsecured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024.

Net proceeds totaling approximately $ 990 million, together with proceeds from the April 2024 issuance of 6.000 % Senior Secured Notes discussed above and cash on hand, were to be used for general corporate purposes, including to refinance outstanding indebtedness (including the senior secured debt maturities in May 2024 and July 2024).

Other Debt Activity

Senior Secured Notes Tender Offer

In January 2024, Vistra Operations used the net proceeds from (i) the December 2023 issuances of the 6.950 % senior secured notes due 2033 and 7.750 % senior unsecured notes due 2031 and (ii) cash on hand, to fund a cash tender offer (Senior Secured Notes Tender Offer) to purchase for cash $ 759 million aggregate principal amount of certain notes, including $ 58 million of 4.875 % senior secured notes due 2024, $ 345 million of 3.550 % senior secured notes due 2024 and $ 356 million of the 5.125 % senior secured notes due 2025.

We recorded an extinguishment gain of $ 6 million on the transaction in the first quarter of 2024.

Accounts Receivable Financing

Accounts Receivable Securitization Program

In April 2024, the Receivables Facility was amended to increase the purchase limit from $ 750 million to $ 1.0 billion and to add Energy Harbor LLC, a direct, wholly owned subsidiary of Energy Harbor, as an Originator.

The Receivables Facility was renewed and amended in July 2024, extending the term of the Receivables Facility to July 2025.

In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy.

RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limit described above to fund its acquisition of the Receivables from the Originators.

RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the performance of the obligations of the Originators and TXU Energy, as the servicer, under the agreements governing the Receivables Facility.

Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings in the consolidated balance sheets.

Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in the consolidated statements of cash flows.

Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers.

The Company records interest expense on amounts advanced.

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

As of December 31, 2024, outstanding borrowings under the Receivables Facility totaled $ 750 million and were supported by $ 1.334 billion of RecCo gross receivables.

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

Repurchase Facility

TXU Energy and the other Originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer).

In July 2024, the Repurchase Facility was renewed until July 2025 while maintaining the facility size of $ 125 million.

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.

Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the Receivables Facility.

There were no outstanding borrowings under the Repurchase Facility as of both December 31, 2024 and December 31, 2023.

Forward Repurchase Obligation

In accordance with the amended UPAs, on December 31, 2024, Vistra closed the acquisition of the Vistra Vision minority interests from Avenue and Nuveen.

Vistra paid Avenue for the purchase of their minority interest in Vistra Vision in full upon closing and paid Nuveen an initial payment at closing, with the remaining payments to Nuveen to be paid in multiple installments through December 31, 2026.

Vistra Vision Holdings' remaining future payments to Nuveen are guaranteed by Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes.

Payments remaining due to Nuveen are as follows:

December 31, 2024

Thereafter 6,960

Unamortized premiums, discounts and debt issuance costs ( 115 )

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

(in millions)

Total scheduled payments under the UPAs $ 1,450

A roll-forward of the noncontrolling interest redemption obligation is as follows (in millions):

Redeemable noncontrolling interest at September 30, 2024

Income attributable to redeemable noncontrolling interest (a)

Dividends to redeemable noncontrolling interest holders

Redeemable noncontrolling interest balance at Closing Date (b)

Principal payment on Closing Date

Forward Repurchase Obligation at December 31, 2024 (c)

(a) Represents accretion attributable to fixed price redemption obligation.

(b) Reclassified to a financing obligation.

Interest Expense and Related Charges

Year Ended December 31,

2024 2023 2022

(in millions)

Interest expense $ 936 $ 654 $ 591

Unrealized mark-to-market net (gains) losses on interest rate swaps ( 53 ) 36 ( 250 )

Amortization of debt issuance costs, discounts, and premiums 34 26 28

Facility Fee expense 15 8 —

Debt extinguishment gain ( 6 ) ( 3 ) ( 1 )

Capitalized interest ( 77 ) ( 37 ) ( 29 )

Other 51 56 29

Total interest expense and related charges $ 900 $ 740 $ 368

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 5.23 %, 5.69 %, and 4.30 % as of December 31, 2024, 2023, and 2022, respectively.

Vistra has both finance and operating leases for real estate, rail cars and equipment.

5 unchanged sentences

2024 2023 2022

(in millions)

Operating lease cost $ 17 $ 12 $ 9

5 unchanged sentences

Short-term lease cost 56 44 47

Sublease income (b) — — ( 7 )

Net lease cost $ 114 $ 99 $ 87

Total lease cost $ 121 $ 114 $ 99

(a) Represents coal stockpile management services, common area maintenance services, and rail car payments based on the number of rail cars used.

(b) Represents sublease income related to real estate leases.

Balance Sheet Information

The following table presents lease related balance sheet information:

(in millions)

Lease assets:

Operating lease right-of-use assets $ 50 $ 51

Finance lease right-of-use assets (net of accumulated depreciation) 160 $ 173

Operating lease right-of-use assets (reported in other noncurrent assets in the consolidated balance sheets) $ 106 $ 50

Finance lease right-of-use assets, net of accumulated amortization (reported in property, plant, and equipment in the consolidated balance sheets) 153 $ 160

Total lease right-of-use assets $ 259 $ 210

Current lease liabilities:

Current lease liabilities (reported in other current liabilities in the consolidated balance sheets):

Operating lease liabilities $ 13 $ 7

1 unchanged sentence

Total current lease liabilities 22 16

Noncurrent lease liabilities:

Noncurrent lease liabilities (reported in other noncurrent liabilities and deferred credits in the consolidated balance sheets):

Operating lease liabilities 98 48

6 unchanged sentences

2024 2023 2022

(in millions)

Non-cash disclosure upon commencement of new lease:

15 unchanged sentences

Operating Lease Finance Lease Total Lease

(in millions)

2025 $ 19 $ 19 $ 38

2026 13 14 27

2027 14 13 27

2028 10 13 23

Thereafter 222 331 553

Total lease payments 286 403 689

Interest ( 51 ) ( 188 ) ( 239 )

Imputed interest

( 175 ) ( 176 ) ( 351 )

Present value of lease liabilities $ 111 $ 227 $ 338

We utilize derivative instruments, such as options, swaps, futures, and forward contracts to manage our exposure to commodity price and interest rate volatility.

Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, fuel oil and natural gas producers, local distribution companies, and energy marketing companies.

Commodity Derivatives

We utilize financial natural gas and financial and physical electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets.

Financial transmission rights and congestion revenue rights are derivative instruments we utilize to hedge electricity price differences between settlement points within regions.

Gains and losses associated with these derivatives are reported in the consolidated statements of operations in operating revenues.

We utilize physical natural gas, coal, emissions, and renewable energy certificate derivatives primarily to hedge future purchased power costs of our retail operations or fuel costs of our generation assets.

Gains and losses associated with these derivatives are reported in the consolidated statements of operations in fuel, purchased power costs, and delivery fees.

Our retail segment procures power from our generation segments to serve future load obligations.

In locations and periods where our load service activities do not naturally offset existing generation portfolio risks, remaining commodity price exposure is managed through portfolio hedging activities.

Interest Rate Swaps

Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows.

Gains and losses associated with these derivatives are reported in the consolidated statements of operations in interest expense and related charges.

As of December 31, 2024, Vistra has entered into the following interest rate swaps:

Notional Amount Expiration Date Rate Range (c)

(in millions, except percentages)

Swapped to fixed (a)

$ 3,000 July 2026 4.64 % - 4.72 %

Swapped to variable (a)

$ 700 July 2026 3.19 % - 3.24 %

Swapped to fixed (b)

$ 2,300 December 2030 4.95 % - 5.51 %

(a) The $ 700 million of pay variable rate and receive fixed rate swaps match the terms of a portion of the $ 3.0 billion pay fixed rate and receive variable rate swaps.

These matched swaps will settle over time and effectively offset the hedged position.

These offsetting swaps expiring in July 2026 hedge our exposure on $ 2.3 billion of variable rate debt through July 2026.

(b) Effective from July 2026 through December 2030.

In November 2024, Vistra entered into $ 675 million notional amount of interest rate swaps effective July 31, 2026 and expiring on December 31, 2030.

These swaps, along with $ 1.625 billion notional amount of interest rate swaps with similar terms entered into in 2023, will hedge our exposure on $ 2.3 billion of floating rate debt from August 2026 through December 2030.

Effect of Derivative Instruments in the Consolidated Balance Sheets

We maintain standardized master netting agreements with certain counterparties that allow for the right to offset accounts payable, accounts receivable and cash collateral paid in order to reduce credit exposure.

The following tables reconcile our gross derivative assets and liabilities as reported in the consolidated balance sheets to the net value on a contract basis, after taking into consideration netting arrangements with counterparties and cash collateral recorded.

December 31, 2024

Derivative Contract Assets

Derivative Contract Liabilities

Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total

(in millions)

Current assets $ 2,551 $ 34 $ 2 $ — $ 2,587

Noncurrent assets 677 62 1 — 740

Current liabilities — — ( 3,333 ) ( 18 ) ( 3,351 )

Noncurrent liabilities ( 2 ) — ( 1,356 ) ( 9 ) ( 1,367 )

Net assets (liabilities) $ 3,226 $ 96 $ ( 4,686 ) $ ( 27 ) $ ( 1,391 )

Offsetting instruments (a)

$ ( 2,532 ) $ ( 28 ) $ 2,532 $ 28 —

Financial collateral (received) pledged (b) $ ( 50 ) $ — $ 233 $ — 183

Net amounts $ 644 $ 68 $ ( 1,921 ) $ 1 $ ( 1,208 )

December 31, 2023

Derivative Contract Assets

Derivative Contract Liabilities

Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total

(in millions)

Current assets $ 3,585 $ 53 $ 7 $ — $ 3,645

Noncurrent assets 565 11 1 — 577

Current liabilities ( 1 ) — ( 5,233 ) ( 24 ) ( 5,258 )

Noncurrent liabilities ( 5 ) — ( 1,659 ) ( 24 ) ( 1,688 )

Net assets (liabilities) $ 4,144 $ 64 $ ( 6,884 ) $ ( 48 ) $ ( 2,724 )

Offsetting instruments (a)

$ ( 3,519 ) $ ( 28 ) $ 3,519 $ 28 —

Financial collateral (received) pledged (b)

$ ( 26 ) $ — $ 970 $ — 944

$ 599 $ 36 $ ( 2,395 ) $ ( 20 ) $ ( 1,780 )

(a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.

(b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements.

Effect of Derivative Instruments in the Consolidated Statements of Operations

The following table summarizes the location and amount of unrealized gains and losses from our derivative instruments recorded in the consolidated statements of operations for the periods presented.

Year Ended December 31,

Derivative (consolidated statements of operations presentation) 2024 2023 2022

(in millions)

Reversals of previously recognized unrealized (gain) loss on derivative instruments:

Commodity contracts unrealized (gain) loss in operating revenues (a) $ 1,140 $ 1,472 $ 1,940

Commodity contracts unrealized (gain) loss in fuel and purchased power expense (a) 73 171 ( 722 )

Interest rate swaps unrealized (gain) loss in interest expense and related charges ( 41 ) ( 78 ) 16

Total reversals of previously recognized unrealized (gain) loss on derivative instruments $ 1,172 $ 1,565 $ 1,234

Unrealized net gains (losses) from changes in fair value on derivative instruments:

Commodity contracts unrealized gain (loss) in operating revenues $ ( 127 ) $ ( 758 ) $ ( 4,103 )

Commodity contracts unrealized gain (loss) in fuel and purchased power expense 69 ( 395 ) 375

Interest rate swaps unrealized gain (loss) in interest expense and related charges 94 42 234

Total unrealized net gains (losses) from changes in fair value on derivative instruments $ 36 $ ( 1,111 ) $ ( 3,494 )

Net gain (loss) on derivative instruments $ 1,208 $ 454 $ ( 2,260 )

(a) Excludes the realized effects of changes in fair value in the month the position settled, amounts related to positions entered into and settled in the same month, and physical retail and wholesale contracts accounted for as derivatives which did not financially settle but realized at the contract's notional and price.

The realized effects of these items are included in operating revenues and fuel and purchased power expense.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes by commodity, excluding our NPNS derivatives that are not recorded at fair value:

December 31, 2024 December 31, 2023

Derivative type Notional Volume Unit of Measure

Natural gas 4,568 5,335 Million MMBtu

Electricity 796,982 800,001 GWh

Financial transmission rights / Congestion revenue rights 248,742 250,895 GWh

Coal 27 35 Million U.S.

Fuel oil 2 3 Million gallons

Emissions 28 24 Million U.S.

Renewable energy certificates 31 29 Million certificates

Interest rate swaps – variable/fixed $ 5,300 $ 5,225 Million U.S.

Interest rate swaps - fixed/variable $ 700 $ 1,300 Million U.S.

Credit Risk-Related Contingent Features of Derivatives

Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement.

Certain of these agreements may require the posting of additional collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:

(in millions)

Fair value of derivative contract liabilities (a) $ ( 1,587 ) $ ( 1,890 )

Offsetting fair value under netting arrangements (b) 724 692

Cash collateral and letters of credit 471 854

Liquidity exposure $ ( 392 ) $ ( 344 )

(a) Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).

(b) Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.

Concentrations of Credit Risk Related to Derivatives

We have concentrations of credit risk with the counterparties to our derivative contracts.

As of December 31, 2024, total credit risk exposure to all counterparties related to derivative contracts totaled $ 3.772 billion (including associated accounts receivable).

The net exposure to those counterparties totaled $ 776 million as of December 31, 2024 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure from any single counterparty totaling $ 262 million.

As of December 31, 2024, the credit risk exposure to the banking and financial sector represented 75 % of the total credit risk exposure and 26 % of the net exposure.

This concentration of credit risk increases the risk that a default by any of our counterparties could have a material effect on our financial condition, results of operations and liquidity.

We maintain credit risk policies with regard to our counterparties to minimize overall credit risk.

These policies authorize specific risk mitigation procedures including, but not limited to, (i) requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our counterparties that allow for netting of positive and negative exposures, and (iii) that detail credit enhancements (such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits) are required in the event of a material downgrade in their credit rating.

FAIR VALUE MEASUREMENTS

Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable.

Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own market assumptions.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy as defined by GAAP:

• Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date.

• Level 2 valuations use over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals.

• Level 3 valuations use unobservable inputs for the asset or liability, typically reflecting our estimate of assumptions that market participants would use in pricing the asset or liability.

The fair value is therefore determined using model-based techniques, including discounted cash flow models.

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

December 31, 2024 December 31, 2023

3 (a) Reclass (a)

(in millions)

Commodity contracts (b) $ 1,923 $ 462 $ 841 $ 5 $ 3,231 $ 2,886 $ 628 $ 630 $ 14 $ 4,158

Interest rate swaps (b) — 96 — — 96 — 64 — — 64

NDTs – equity securities (c)(d) 1,560 — — — 1,560 638 — — — 638

NDTs – debt securities (c)(e) 83 1,976 — — 2,059 — 734 — — 734

Sub-total $ 3,566 $ 2,534 $ 841 $ 5 6,946 $ 3,524 $ 1,426 $ 630 $ 14 5,594

Assets measured at net asset value (f):

NDTs – equity securities (c)(d)(f) 821 579

Total assets $ 7,767 $ 6,173

Commodity contracts (b) $ 2,118 $ 975 $ 1,593 $ 5 $ 4,691 $ 3,815 $ 1,395 $ 1,674 $ 14 $ 6,898

Interest rate swaps (b) — 27 — — 27 — 48 — — 48

Total liabilities $ 2,118 $ 1,002 $ 1,593 $ 5 $ 4,718 $ 3,815 $ 1,443 $ 1,674 $ 14 $ 6,946

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

This reclassification represents the adjustment needed to reconcile to the gross amounts presented in the consolidated balance sheets.

(b) See Note 11 for additional information.

(c) NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities.

These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

The NDT investments are included in Investments in the consolidated balance sheets.

There were no significant concentrations of credit risk from an individual counterparty or groups of counterparties in our NDT portfolio as of December 31, 2024.

(d) The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S.

equity investments and the MSCI EAFE Index for non-U.S.

equity investments.

(e) The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio.

The debt securities are weighted with government and investment grade corporate bonds.

Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S.

developed bonds, emerging market bonds, loans and treasury inflation-protected securities.

The debt securities had an average coupon rate of 3.99 % and 3.19 % as of December 31, 2024 and 2023, respectively, and an average maturity of 7 years and 11 years as of December 31, 2024 and 2023, respectively.

NDT debt securities held as of December 31, 2024 mature as follows:

$ 1.045 billion in one to five years, $ 599 million in five to 10 years and $ 415 million after 10 years.

(f) Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair values and therefore are not classified in the fair value hierarchy.

This amount is presented to permit reconciliation of this table to the amounts presented in the consolidated balance sheets.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of December 31, 2024 and 2023:

December 31, 2024

Contract Type (a) Assets Liabilities Total, Net

Valuation Technique Significant Unobservable Input Range (b) Average (b)

(in millions)

Electricity purchases and sales $ 606 $ ( 1,399 ) $ ( 793 ) Income Approach Hourly price curve shape (c) $ — to $ 95 $ 48

Illiquid delivery periods for hub power prices (d)

$ 25 to $ 140 $ 83

Market Heat Rates (d)

$ 30 to $ 150 $ 90

Options 6 ( 139 ) ( 133 ) Option Pricing Model Natural gas to power correlation (e) 10 % to 100 % 55 %

Power and natural gas volatility (e) 5 % to 710 % 358 %

Financial transmission rights/Congestion revenue rights

190 ( 25 ) 165 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 35 ) to $ 20 $ ( 8 )

Natural gas 29 ( 30 ) ( 1 ) Income Approach Natural gas basis (h) $ — to $ 10 $ 5

Illiquid delivery periods (i) $ — to $ 5 $ 2

Other (j) 10 — 10

Total $ 841 $ ( 1,593 ) $ ( 752 )

December 31, 2023

Contract Type (a) Assets Liabilities Total, Net

Valuation Technique Significant Unobservable Input Range (b) Average (b)

(in millions)

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

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/Congestion revenue rights

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

Natural gas 9 ( 112 ) ( 103 ) Income Approach Natural gas basis (h) $ — to $ 15 $ 6

Illiquid delivery periods (i)

$ — to $ 5 $ 4

Other (j) 14 ( 18 ) ( 4 )

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

(a) Electricity purchase and sales contracts include (i) power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts.

(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.

The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount.

(c) Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices.

(d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability.

(e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM.

(f) While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid.

(g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.

(h) Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices.

(i) Primarily based on the historical forward natural gas fixed prices.

(j) Other includes contracts for coal and environmental allowances.

The following table presents the changes in fair value of the Level 3 assets and liabilities:

Year Ended December 31,

2024 2023 2022

(in millions)

Net liability balance at beginning of period $ ( 1,044 ) $ ( 1,219 ) $ ( 360 )

Total unrealized valuation gains (losses) ( 175 ) ( 765 ) ( 1,382 )

Purchases, issuances and settlements (a):

Purchases 266 222 185

Issuances ( 26 ) ( 30 ) ( 62 )

Settlements 137 136 345

Transfers into Level 3 (b) ( 15 ) ( 48 ) ( 30 )

Transfers out of Level 3 (b) 118 660 85

Net liabilities assumed in connection with the Energy Harbor Merger ( 13 ) — —

Net change 292 175 ( 859 )

Net liability balance at end of period $ ( 752 ) $ ( 1,044 ) $ ( 1,219 )

Unrealized valuation (losses) relating to instruments held at end of period $ ( 416 ) $ ( 676 ) $ ( 977 )

(a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income.

Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.

(b) Includes transfers due to changes in the observability of significant inputs.

All Level 3 transfers during the periods presented are in and out of Level 2.

For the year ended December 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and natural gas derivatives where forward pricing inputs have become observable.

For the year ended December 31, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable.

For the year ended December 31, 2022, transfers into Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power, natural gas, and coal derivatives where forward pricing inputs have become observable.

Assets and Liabilities Recorded on a Non-Recurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis.

These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances.

These assets and liabilities can include inventories, assets acquired and liabilities assumed in business combinations, goodwill and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale.

The Energy Harbor Merger was accounted for under the acquisition method which requires all assets acquired and liabilities assumed in the acquisition be recorded at fair value at the acquisition date.

See Note 2 for additional information.

Fair Value of Debt

December 31, 2024 December 31, 2023

Fair Value Hierarchy Carrying Amount Fair

Value Carrying Amount Fair

(in millions)

Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,435 $ 2,478 $ 2,456 $ 2,500

BCOP Credit Facilities Tax Credit Bridge Loan Level 3

Vistra Zero Term Loan B Facility Level 2

Vistra Operations Senior Notes Level 2 12,366 12,428 11,881 11,752

Energy Harbor Revenue Bonds Level 2

Equipment Financing Agreements Level 3 54 53 65 62

Forward Repurchase Obligation

1,335 1,335 — —

We determine fair value in accordance with accounting standards.

We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values.

Where relevant, these prices are validated through subscription services, such as Bloomberg.

ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations (ARO) primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs.

AROs are based on legal obligations associated with enacted law, regulatory, or contractual retirement requirements for which decommissioning timing and cost estimates are reasonably estimable.

The following table summarizes the changes to our current and noncurrent ARO liabilities for the years ended December 31, 2024 and 2023:

Nuclear Plant Decommissioning Land Reclamation, Coal Ash and Other Total

(in millions)

Liability at December 31, 2022

$ 1,688 $ 749 $ 2,437

Accretion (a)

Adjustment for change in estimates (b)

Payments — ( 81 ) ( 81 )

Liability at December 31, 2023

1,742 796 2,538

Accretion (a)

Adjustment for change in estimates (b)

Adjustment for obligations assumed through acquisitions 1,368 — 1,368

Payments — ( 88 ) ( 88 )

Liability at December 31, 2024

3,240 838 4,078

Less amounts due currently — ( 142 ) ( 142 )

Noncurrent liability at December 31, 2024

$ 3,240 $ 696 $ 3,936

(a) For the year ended December 31, 2024, nuclear plant decommissioning accretion includes $ 74 million of accretion expense recognized in operating costs in the consolidated statements of operations and $ 56 million reflected as a change in regulatory liability in the consolidated balance sheets.

For the year ended December 31, 2023, nuclear plant decommissioning accretion reflected as a change in regulatory liability in the consolidated balance sheets.

(b) Includes non-cash additions to asset retirement costs included in property, plant, and equipment of $ 52 million and $ 67 million for the years ended December 31, 2024 and 2023, respectively.

For the next five years, Vistra is projected to spend approximately $ 546 million (on a nominal basis) to achieve its mining reclamation and other coal ash remediation objectives.

Nuclear Decommissioning AROs

AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and the facilities acquired from Energy Harbor which include the Beaver Valley, Perry and Davis-Besse plants in PJM (the PJM nuclear facilities).

To estimate our nuclear decommissioning obligations we use a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates.

As of December 31, 2024, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $ 1.797 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $ 2.249 billion.

The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $ 452 million recorded to the consolidated balance sheets in other noncurrent liabilities and deferred credits since any excess funds in the NDT after decommissioning our Comanche Peak plant would be refunded to Oncor.

The carrying value of our ARO for our PJM nuclear facilities was recorded at fair value on the Merger Date.

ARO accretion expense attributable to the PJM nuclear facilities is reflected in operating costs in the consolidated statements of operations.

ARO estimates for the PJM nuclear facilities will be evaluated on an individual unit basis at least every five years unless triggering events warrant a more frequent review.

Any changes in ARO estimates are recorded as an increase or decrease in ARO liability along with a corresponding change to asset retirement cost asset within property, plant, and equipment in the consolidated balance sheets;

however, if the ARO estimate decreases by more than the remaining ARO asset, the balance of the change is recorded as a reduction to operating costs in the consolidated statement of operations.

PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS

Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries.

Oncor is a participant in the Retirement Plan.

Effective January 1, 2018, Vistra entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra.

As Vistra accounts for its interests in the Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension benefit information presented below.

The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA.

The Retirement Plan provides benefits to participants under one of two formulas:

(i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings.

Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.

It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations.

Since 2012, the Retirement Plan has been closed to new participants and the only participants who remain in the Retirement Plan are employees who were active prior to 2012, including retired collective bargaining unit employees.

Accordingly, ongoing expenses associated with the Retirement plan are immaterial, including expenses associated with pensions plans acquired from Dynegy and Energy Harbor.

Vistra and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents.

The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service.

Pension and OPEB Costs

The following table summarizes the total benefit costs of our pension and OPEB plans for the years ended December 31, 2024, 2023, and 2022.

The individual components of benefit costs, including service cost, interest cost, expected return on assets and the net amortization of unrecognized amounts from accumulated other comprehensive income were immaterial.

Year Ended December 31,

2024 2023 2022

(in millions)

Pension costs $ 9 $ 9 $ 2

OPEB costs 5 5 4

Total benefit costs recognized as expense $ 14 $ 14 $ 6

Market-Related Value of Assets Held in Pension Benefit Trusts

We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs.

We include all gains or losses in the market-related value of assets over a rolling four-year period.

Each year, 25 % of such gains and losses for the current year and for each of the preceding three years is included in the market-related value.

Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

Detailed Information Regarding Pension Plans and OPEB Benefits

The following information is based on a December 31, 2024, 2023, and 2022 measurement dates:

Retirement Plan OPEB Plans

Year Ended December 31, Year Ended December 31,

2024 2023 2022 2024 2023 2022

Assumptions Used to Determine Benefit Obligations at Period End:

Discount rate 5.63 % 4.97 % 5.16 % 5.62 % 4.98 % 5.18 %

Expected rate of compensation increase (Vistra Plan) 3.50 % 3.64 % 3.79 %

Expected rate of compensation increase (Dynegy Plan) 4.46 %

Interest crediting rate for cash balance plans 3.75 % 3.50 % 3.00 %

Retirement Plan OPEB Plans

Year Ended December 31, Year Ended December 31,

2024 2023 2024 2023

(in millions, except percentages)

Change in Pension and Postretirement Benefit Obligations:

Projected benefit obligation at beginning of period $ 425 $ 449 $ 108 $ 110

Acquisitions 23 — — —

Service cost 2 3 1 1

Interest cost 21 21 5 5

Participant contributions — — 3 3

Plan amendments — 1 — —

Actuarial (gain) loss ( 24 ) 10 ( 7 ) 1

Benefits paid ( 38 ) ( 59 ) ( 11 ) ( 12 )

Projected benefit obligation at end of year $ 409 $ 425 $ 99 $ 108

Accumulated benefit obligation at end of year $ 408 $ 422 $ — $ —

Change in Plan Assets:

Fair value of assets at beginning of period $ 285 $ 320 $ 12 $ 29

Acquisitions 18 — — —

Employer contributions 19 — 8 9

Participant contributions — — 2 3

Actual gain on assets 1 24 1 2

Transfers — — ( 2 ) ( 19 )

Benefits paid ( 38 ) ( 59 ) ( 11 ) ( 12 )

Fair value of assets at end of year $ 285 $ 285 $ 10 $ 12

Funded Status:

Projected benefit obligation $ ( 409 ) $ ( 425 ) $ ( 99 ) $ ( 108 )

Fair value of assets 285 285 10 12

Funded status at end of year $ ( 124 ) $ ( 140 ) $ ( 89 ) $ ( 96 )

Retirement Plan OPEB Plans

Year Ended December 31, Year Ended December 31,

2024 2023 2024 2023

Amounts Recognized in the Balance Sheet Consist of:

Investments $ 1 $ — $ 2 $ 3

Other current liabilities — — ( 8 ) ( 9 )

Other noncurrent liabilities ( 125 ) ( 140 ) ( 83 ) ( 90 )

Net liability recognized $ ( 124 ) $ ( 140 ) $ ( 89 ) $ ( 96 )

Amounts Recognized in Accumulated Other Comprehensive Income Consist of:

Net actuarial (gain) loss $ ( 5 ) $ 4 $ ( 22 ) $ ( 15 )

Prior services cost — 3 1 1

Net actuarial (gain) loss and prior service cost $ ( 5 ) $ 7 $ ( 21 ) $ ( 14 )

Fair Value Measurement of Pension and OPEB Plan Assets

Retirement Plan

As of December 31, 2024 and 2023, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following:

(in millions)

Asset Category:

Cash commingled trusts $ 6 $ 4

Equity securities:

Global equities 86 82

Fixed income securities:

Corporate bonds (a) 79 82

Government bonds 42 54

Other (b) 28 18

Real estate 27 28

Hedge funds 17 17

Total assets measured at net asset value $ 285 $ 285

(a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

(b) Consists primarily of high-yield bonds, emerging market debt, bank loans, securitized bonds and private investment grade fixed income.

As of December 31, 2024 and 2023, the Vistra OPEB plan assets measured at fair value totaled $ 10 million and $ 12 million, respectively.

At December 31, 2024 and 2023, assets consisted of $ 7 million and $ 9 million, respectively, of comingled funds valued at net asset value and $ 3 million and $ 3 million, respectively, of municipal bond and cash equivalent mutual funds classified as Level 1.

Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO) in Excess of Plan Assets

The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets.

(in millions)

Pension Plans with PBO and ABO in Excess of Plan Assets:

Projected benefit obligations $ 409 $ 425

Accumulated benefit obligation $ 408 $ 422

Plan assets $ 285 $ 285

Retirement Plan Investment Strategy and Asset Allocations

Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions.

Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S.

Treasuries and agency securities, and money market instruments.

Equity securities are held to enhance returns by participating in a wide range of investment opportunities.

International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets.

Real estate, hedge funds, and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential.

The target asset allocation ranges of pension plan investments by asset category are as follows:

Retirement Plan

Target Allocation Ranges

Asset Category:

Vistra Plan Dynegy Plan Energy Harbor Plan

Fixed income securities 50 % - 70 % 40 % - 50 % 45 % - 55 %

Global equity securities 20 % - 28 % 28 % - 38 % 30 % - 38 %

Real estate 6 % - 10 % 7 % - 15 % 5 % - 10 %

Credit strategies 2 % - 6 % 4 % - 8 % 4 % - 8 %

Hedge funds 2 % - 6 % 4 % - 8 % 1 % - 5 %

Retirement Plan Expected Long-Term Rate of Return on Assets Assumption

The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies.

The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.

Retirement Plan

Expected Long-Term Rate of Return

Vistra Plan Dynegy Plan Energy Harbor Plan

Fixed income securities 5.9 % 5.5 % 4.6 %

Global equity securities 7.2 % 7.2 % 7.2 %

Real estate 5.8 % 5.8 % 5.8 %

Credit strategies 7.4 % 7.4 % 7.4 %

Hedge funds 7.3 % 7.3 % 7.3 %

Weighted average 6.3 % 6.3 % 5.8 %

Benefit Plan Assumed Health Care Cost Trend Rates

The following tables provide information regarding the assumed health care cost trend rates.

Assumed Health Care Cost Trend Rates-Not Medicare Eligible:

Health care cost trend rate assumed for next year 7.00 % 7.00 %

Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 %

Year that the rate reaches the ultimate trend rate 2034 2033

Assumed Health Care Cost Trend Rates-Medicare Eligible:

Health care cost trend rate assumed for next year (Vistra Plan) 15.70 % 12.90 %

Health care cost trend rate assumed for next year (Split-Participant Plan) 13.80 % 12.30 %

Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 %

Year that the rate reaches the ultimate trend rate 2034 2033

Significant Concentrations of Risk

The plans' investments are exposed to risks such as interest rate, capital market and credit risks.

We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us.

While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so.

There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.

Assumed Discount Rate

We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2024 consisted of 490 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings.

Contributions

Contributions to the Retirement Plan for the years ended December 31, 2024, 2023, and 2022 totaled $ 19 million, zero , and zero , respectively, and contributions in 2025 are expected to total $ 25 million.

OPEB plan funding for each of the years ended December 31, 2024, 2023, and 2022 totaled $ 8 million, $ 9 million, and $ 9 million, respectively, and funding in 2025 is expected to total $ 8 million.

Future Benefit Payments

Estimated future benefit payments to beneficiaries are as follows:

2025 2026 2027 2028 2029 2030-2034

(in millions)

Pension benefits $ 33 $ 34 $ 43 $ 32 $ 32 $ 151

OPEB $ 9 $ 9 $ 9 $ 8 $ 8 $ 36

Qualified Savings Plans

Our employees may participate in a qualified savings plan (the Thrift Plan).

This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA.

Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75 % of their regular salary or wages or the maximum amount permitted under applicable law.

Employees who earn more than such threshold may contribute from 1 % to 20 % of their regular salary or wages.

Employer matching contributions are also made in an amount equal to 100 % ( 75 % for employees covered under the traditional formula in the Retirement Plan) of the first 6 % of employee contributions.

Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options.

Aggregate employer contributions to the qualified savings plans totaled $ 46 million, $ 33 million, and $ 33 million for the years ended December 31, 2024, 2023, and 2022, respectively.

COMMITMENTS AND CONTINGENCIES

2 unchanged sentences

Long-Term Service and Maintenance Contracts (a) Coal transportation agreements Pipeline transportation and storage reservation fees Water

(in millions)

2025 $ 227 $ 59 $ 187 $ 9

10 unchanged sentences

We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions.

Material guarantees are discussed below.

Letters of Credit

As of December 31, 2024, we had outstanding letters of credit totaling $ 2.935 billion as follows:

• $ 2.408 billion to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;

• $ 2.560 billion to support commodity risk management and collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;

• $ 248 million to support battery and solar development projects;

2 unchanged sentences

• $ 16 million for other credit support requirements.

As of December 31, 2023, we had outstanding surety bonds totaling $ 935 million to support performance under various contracts and legal obligations in the normal course of business.

As of December 31, 2024, we had outstanding surety bonds totaling $ 1.087 billion to support performance under various contracts and legal obligations in the normal course of business.

Litigation and Regulatory Proceedings

17 unchanged sentences

In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 5 -year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint.

Ohio House Bill 6 ("HB6") — In July 2019, Ohio adopted a law referred to as HB6, which, among other things, provided subsidies for two nuclear power plants which we acquired in March 2024 upon the closing of our merger with Energy Harbor.

We had opposed enactment of that subsidy legislation at the time, and the nuclear subsidies were repealed in 2021 prior to any subsidies being distributed.

Attorney's Office conducted an investigation into the activities related to the passage of HB6, and Energy Harbor received a grand jury subpoena in July 2020 requiring production of certain information related to that investigation.

Energy Harbor completed its responses to that subpoena by December 2021.

In August 2020, the Ohio Attorney General filed a civil Racketeer Influenced and Corrupt Organizations Act (RICO) complaint against FirstEnergy Corp.

and various Energy Harbor companies related to passage of HB6 ( State of Ohio ex rel.

Dave Yost, Ohio Attorney General v.

FirstEnergy Corp., et al.

, Franklin County, Ohio Common Pleas Court Case No.

20CV006281 and State of Ohio ex rel.

Dave Yost, Ohio Attorney General v.

Energy Harbor Corp.

, et al., Franklin County, Ohio Common Pleas Court Case No.

Motions to dismiss those cases remain pending and the case is currently stayed.

Winter Storm Uri Legal Proceedings

Repricing Challenges — In March 2021, we filed an appeal in the Third Court of Appeals in Austin, Texas (Third Court of Appeals), challenging the PUCT's February 15 and February 16, 2021 orders governing ERCOT's determination of wholesale power prices during load-shedding events.

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

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

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

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

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

In 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.

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.

Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, and the Texas Attorney General initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges for generators arising from the event, including performance and fuel and supply issues.

We responded to all those investigatory requests.

9 unchanged sentences

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.

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

The plaintiffs have petitioned the Texas Supreme Court to review that decision.

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

Moss Landing 300 Battery Fire

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site.

We are working closely with all local, state, and federal regulatory authorities on the response, and we are investigating the cause of the fire.

We are also responding to various regulatory bodies, including the CPUC, the EPA, and others investigating the incident.

Finally, two lawsuits have been filed in California state court against Vistra, LG, and others, arising from the event.

Unleashing American Energy Executive Order

In January 2025, President Trump issued a series of executive orders, including an order titled Unleashing American Energy (the Order) that ordered that all federal agencies are to review all existing regulations, orders, and other actions for consistency with the policy goals, and develop an action plan within 30 days to resolve any policy inconsistencies.

The Order requires the EPA to review the GHG, CSAPR, Legacy CCR and ELG rules discussed below.

Additionally, the Order states the U.S.

Attorney General may request a stay of the litigation involving these rules while the EPA conducts its reviews.

Greenhouse Gas Emissions (GHG)

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 generation units.

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

Court of Appeals for the District of Columbia Circuit (D.C.

Circuit Court) vacated the ACE rule, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action.

In June 2022, the U.S.

Supreme Court issued an opinion reversing the D.C.

Circuit Court's decision, and finding that the EPA exceeded its authority under Section 111 of the Clean Air Act when the EPA set emission requirements in the CPP based on generation shifting.

In October 2022, the D.C.

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 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.

In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019.

In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units.

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

Starting in 2030, the rule would begin to require more CO 2 emissions control at certain existing fossil fuel-fired steam generating units, with more stringent standards beginning in 2032 for coal-fired units that plan to operate for a longer period of time.

For new natural gas combustion turbines that operate more frequently, the rule would phase in increasingly stringent CO 2 requirements over time.

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

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

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)

Under the rule, existing coal-fired steam generation units that will operate on or after January 1, 2039 must start complying with their standards of performance (based on application of CCS with 90 percent capture) by January 1, 2032.

Units that are permanently retiring before January 1, 2039, but after December 31, 2031, must start complying with their standards of performance (based on co-firing with 40 percent natural gas on a heat input basis) beginning on January 1, 2030.

Units permanently retiring by January 1, 2032 are exempt from the rule.

Given our previously announced coal unit retirement commitments, our Martin Lake and Oak Grove plants are the only coal units that are subject to this rule.

Our Graham, Lake Hubbard, Stryker Creek and Trinidad oil/natural gas facilities are also regulated under this rule.

None of our existing large or small combustion turbines are subject to this rule.

The rule also regulates any new gas units.

For new combustion turbine units, the rule establishes three different categories depending on how intensively those units are operated, with immediate compliance obligations for all three categories but more stringent standards beginning in 2032 only for the category of units operating the most intensively.

Following finalization of the rule in May 2024, 17 petitions for review from various states, industry groups, and companies were filed in the D.C.

Circuit Court along with multiple motions to stay the rule.

We are participating in an industry coalition challenging the rule.

In July 2024, the D.C.

Circuit Court denied the motions to stay and a number of parties subsequently filed an emergency request with the U.S.

Supreme Court to stay the rule which was denied in October 2024.

Oral argument on the merits of the legal challenges to the rule was held in December 2024 before the D.C.

Circuit Court.

In February 2025, the D.C.

Circuit granted the unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

Cross-State Air Pollution Rule (CSAPR) and Good Neighbor Plan

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

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We, along with many other companies, trade groups, states, and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions.

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

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

In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP).

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

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

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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.

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

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

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

In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the 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.

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

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

In February 2025, the Department of Justice filed a motion on behalf of the EPA in the Fifth Circuit Court, seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

In February 2025, the State of Texas filed a response opposing the requested abatement, which we joined.

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

In a related action brought by other states and parties challenging the GNP FIP, in June 2024, the U.S.

Supreme Court granted a stay of the GNP FIP pending a review of the merits by the D.C.

Circuit Court and any further appeal to the U.S.

Supreme Court.

As a result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP.

In February 2025, the D.C.

Circuit Court denied a motion filed by the Department of Justice on behalf of the EPA, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

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

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In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO 2 emissions from the plant.

The proposed agreed order associated with the SIP proposal reduces emission limits as of January 2022.

The proposed agreed order associated with the SIP proposal reduced emission limits as of January 2022.

Emission reductions required are those necessary to demonstrate attainment with the NAAQS.

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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.

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

In August 2024, the EPA proposed a Finding of Failure to attain the SO 2 standard for Rusk and Panola Counties, a partial approval and partial disapproval of the Texas SIP and a proposed federal plan for the area.

In December 2024, the EPA finalized the Finding of Failure to attain the standard and stated that it would take final action of the SIP partial approval and disapproval in a future action.

In February 2025, we, along with the State of Texas, filed a challenge to the Finding of Failure in the Fifth Circuit Court.

Particulate Matte r

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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.

Based on 2021-2023 design value associated with the rule, we have just four plants (Calumet (Illinois), Dicks Creek and Miami Fort (Ohio), and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard.

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

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Notifications were made to Texas, Illinois, and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021.

In 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 May 2024, the EPA published the final ELG rule revisions, which contain new requirements for legacy wastewater and combustion residual leachate.

The final rule also leaves in place the subcategory for facilities that permanently cease coal combustion by 2028.

We are reviewing the rule for impact but believe it will require additional treatment costs for legacy wastewaters during pond closure activities and combustion residual leachate.

At this time, we don't expect the impact of these additional treatment costs to be material.

A number of parties have since challenged the rule and that case is pending in the U.S.

Court of Appeals for the Eighth Circuit.

We are not a party to that litigation.

In February 2025, the Department of Justice on behalf of the EPA filed an unopposed motion seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

Coal Combustion Residuals (CCR) Rule Revisions and Extension Applications

In August 2018, the D.C.

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The 2020 final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue).

Prior to the November 2020 deadline, 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.

Circuit Court, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020.

Also, in November 2020, the EPA finalized a rule that would allow an alternative liner demonstration for certain qualifying facilities.

In November 2020, we submitted an 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.

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

In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications.

In addition, in January 2022, the EPA also made a series of public statements, including in a press release, that purported to impose new, more onerous closure requirements for CCR units.

The EPA issued these new purported requirements without prior notice and without following the legal requirements for adopting new rules.

These new purported requirements announced by the EPA are contrary to existing regulations and the EPA's prior positions.

In April 2022, we, along with the Utility Solid Waste Activities Group (USWAG), a trade association of over 130 utility operating companies, energy companies, and certain other industry associations, filed petitions for review with the D.C.

Circuit Court and have asked the court to determine that the EPA cannot implement or enforce the new purported requirements because the EPA has not followed the required procedures.

The State of Texas and the TCEQ 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 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.

Legacy CCR Rulemaking

In May 2024, the EPA published a final rule that expands coverage of groundwater monitoring and closure requirements to the following two new categories of units:

(a) legacy CCR surface impoundments which are CCR surface impoundments that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015 and (b) "CCR management units" (CCRMUs) which generally could encompass noncontainerized ash deposits greater than one ton and impoundments and landfills that closed prior to October 19, 2015.

As part of the rule, the EPA identified numerous CCR management units across the country, including ten of our potential units.

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

CCRMUs with 1,000 or more tons of CCR must comply with the CCR's groundwater monitoring, corrective action, closure and post-closure requirements.

For CCRMUs, complete facility evaluation reports are due within 33 months after publication of the rule, initial groundwater reports are due January 31, 2029, and the deadline to initiate closure, if needed, will start in 2029.

Closure of the CCRMUs may also be deferred beyond those dates depending on certain factors, including where the CCRMU is located beneath critical infrastructure.

In addition, certain closures may not be required when closure was previously approved under a state program.

Because facility evaluation reports will determine our unit-specific compliance obligations, we cannot determine them at this time.

In August 2024, we, along with USWAG, several other generating companies, and 17 states, including Texas, filed a challenge to the rule in the D.C.

Circuit Court.

In February 2025, the D.C.

Circuit Court granted an unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

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 May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options.

In May 2018, Prairie Rivers Network (PRN) filed a citizen suit in federal court in Illinois against Dynegy Midwest Generation, LLC (DMG), alleging violations of the Clean Water Act for alleged unauthorized discharges.

In August 2018, we filed a motion to dismiss the lawsuit.

In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor.

In June 2021, the Seventh Circuit Court affirmed the district court's dismissal of the lawsuit.

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.

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.

We are addressing these CCR surface impoundments in accordance with the federal CCR rule.

In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General.

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Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter.

Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the newly implemented Illinois Coal Ash regulation (discussed below) and close the site by removal.

Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the Illinois Coal Ash regulation (discussed below) and close the site by removal.

In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments.

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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).

These proposed closure costs are reflected in the ARO in the consolidated balance sheets (see Note 13 for additional information).

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

We are addressing these CCR surface impoundments in accordance with the federal CCR rule.

In July 2019, coal ash disposal and storage legislation in Illinois was enacted.

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The rule does not mandate closure by removal at any site.

In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule and that case remains pending.

Other parties have also filed appeals of certain provisions of the final rule.

In May 2021, we, along with other industry petitioners, filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule.

In March 2024, the Illinois Fourth Judicial District issued a decision denying the industry petitions.

We do not anticipate any impacts from this decision.

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

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

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

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

The Illinois coal ash rule was finalized in April 2021 and does not require removal.

However, the rule required us to undertake further site-specific evaluations required by each program.

We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been approved by the IEPA.

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.

The CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the costs of closure methods that our operations and environmental services teams determined were appropriate based on the existing closure requirements at the time we recorded those ARO liabilities, and is reasonably possible for those to increase once the IEPA determines final closure requirements.

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

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filed a motion at the FERC requesting that the FERC on remand reverse its prior decision and either find that auction results were not just and reasonable and order Dynegy to pay refunds to Illinois or, in the alternative, initiate an evidentiary hearing and discovery.

We filed a response to this motion and will continue to vigorously defend our position.

In June 2022, the FERC issued an order on remand establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 planning resource auction.

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

In June 2024, the FERC issued an order for an evidentiary hearing (or a trial before a FERC administrative law judge) to determine what the FERC cited as "disputed issues of material fact" that it believes cannot be resolved on the existing record and, in October 2024, issued an order dismissing our request for rehearing of the June 2024 order.

We will continue to vigorously defend our position.

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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 2024 and March 2028, 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 February 2025 and March 2028, but remain effective thereafter unless and until terminated by either party.

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

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Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $ 16.2 billion limit for a single incident.

As required, we insure against a possible nuclear incident at our Comanche Peak facility resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP).

As required, we insure against a possible nuclear incident at our nuclear facilities resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP).

Under the SFP, in the event of any single nuclear liability loss in excess of $ 500 million at any nuclear generation facility in the U.S., each operating licensed reactor in the U.S.

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The potential assessment is triggered by a nuclear liability loss in excess of $ 500 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 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.

We maintain nuclear accident decontamination and reactor damage stabilization insurance and non-nuclear accident related property damage for our Beaver Valley, Davis-Besse and Perry facilities in the amount of $ 1.5 billion each (subject to a $ 20 million deductible per accident), and losses excluded or above such limits are self-insured.

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

Coverage at Comanche Peak provides for weekly payments per unit up to $ 4.5 million for the first 52 weeks and up to $ 2.7 million for a remaining 21 weeks for non-nuclear and up to $ 3.6 million for a remaining 71 weeks for nuclear property damage outages.

The total maximum coverage is $ 291 million for non-nuclear property damage and $ 490 million for nuclear property damage outages.

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.

Common Stock Issuances and Repurchases

Coverage at Beaver Valley, Davis-Besse and Perry facilities provide for weekly payments per unit up to $ 2.5 million for the first 52 weeks and up to $ 1.5 million for a remaining 52 weeks for non-nuclear and up to $ 2 million for a remaining 110 weeks for nuclear property damage outages.

The total maximum coverage is $ 208 million for non-nuclear property damage and $ 350 million for nuclear damage outages.

There are two units at Comanche Peak and Beaver Valley, and coverage amounts applicable to each unit will reduce to 80 % if both units are out of service at the same time as a result of the same accident.

Issuances and Repurchases

Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2024, 2023, and 2022 are reflected in the table below.

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Shares issued (a) 5,117,434 — 5,117,434

Shares retired ( 18,391 ) — ( 18,391 )

Shares repurchased (b) — ( 16,560,328 ) ( 16,560,328 )

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(b) Shares repurchased include 58,817 , 318,632 , and 78,087 of unsettled shares as of December 31, 2024, 2023, and 2022, respectively.

Share Repurchase Programs

Current Share Repurchase Program — In October 2021, we announced that the Board authorized a share repurchase program (Share Repurchase Program) under which up to $ 2.0 billion of our outstanding shares of common stock may be repurchased.

The Share Repurchase Program became effective on October 11, 2021, at which time it superseded the 2020 Share Repurchase Program (described below) and any authorization remaining as of such date.

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.

C ommon Stock Dividends

Dividends are subject to declaration by the Board and may be subject to numerous factors at the time of declaration.

These factors include, but are not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law, and any contractual limitations, such as the cumulative dividend requirements described in the certificates of designation of our outstanding preferred stock.

Dividends per common share totaled $ 0.8735 , $ 0.8205 , and $ 0.7240 in the years ended December 31, 2024, 2023, and 2022, respectively.

In February 2025, the Board declared a quarterly dividend of $ 0.2235 per share of common stock that will be paid in March 2025.

Share Repurchase Program

In October 2021, the Board authorized a share repurchase program (Share Repurchase Program).

Under this program, shares of the Company's common stock may be repurchased in open market transactions, privately negotiated transactions, or other means in accordance with federal securities laws.

The timing, number, and value of shares repurchased will be determined at our discretion, considering factors such as capital allocation priorities, stock market price, general market and economic conditions, legal requirements, and compliance with debt agreements and preferred stock certificates of designation.

Amount Authorized for Share Repurchases

(in billions)

Board Authorization Dates:

February 2024

Cumulative authorization at December 31, 2024

The following table provides information about our repurchases of common stock for the period between January 1, 2022 and February 24, 2025.

$6.750 Billion Board Authorization

1 unchanged sentence

Per Share Amount Paid for Shares Repurchased Amount Available for Additional Repurchases at the End of the Period

(in millions, except share amounts and price paid per share)

Year Ended December 31, 2022 78,470,547 $ 23.40 $ 1,836

19,330,365 $ 21.16 $ 409

Year Ended December 31, 2023 44,994,499 27.89 1,255

78,470,547 $ 23.40 $ 1,836

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

Year Ended December 31, 2024 16,560,328 74.96 1,241

January 1, 2022 through December 31, 2024 (a) 140,025,374 $ 30.94 $ 4,332 $ 2,009

January 1, 2025 through February 24, 2025 848,866 163.23 139

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

January 1, 2022 through February 24, 2025 140,874,240 $ 31.74 $ 4,471 $ 1,870

(a) Shares repurchased include 58,817 of unsettled shares for $ 8 million as of December 31, 2024.

(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 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.

The 2020 Share Repurchase Program was effective on January 1, 2021.

In the year ended December 31, 2021, 8,658,153 shares of our common stock were repurchased under the 2020 Share Repurchase Program for approximately $ 175 million at an average price of $ 20.21 per share of common stock.

The 2020 Share Repurchase Program was superseded by the Share Repurchase Program described above in October 2021.

Preferred Stock

On October 15, 2021 (Series A Issuance Date), we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Series A Offering).

The net proceeds of the Series A Offering were approximately $ 990 million, after deducting underwriting commissions and offering expenses.

We intend to use the net proceeds from the Series A Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (described above).

On December 10, 2021 (Series B Issuance Date), we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering).

The net proceeds of the Series B Offering were approximately $ 985 million, after deducting underwriting commissions and offering expenses.

We intend to use the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments.

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.

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 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

Board Declaration Date Payment

Date Per Share Amount Board Declaration Date Payment

Date Per Share Amount

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

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).

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

Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.07 %), plus a spread of 6.93 % per annum.

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

Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each April 15 and October 15, commencing on April 15, 2022, when, as and if declared by the Board.

The annual dividend rate on each share of Series B Preferred Stock is 7.0 % from the Series B Issuance Date to, but excluding December 15, 2026 (Series B First Reset Date).

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

Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.26 %), plus a spread of 5.74 % per annum.

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

Cumulative cash dividends on the Series B Preferred Stock are payable semiannually, in arrears, on each June 15 and December 15, commencing on June 15, 2022, when, as and if declared by the Board.

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 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 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.

Dividend Restrictions

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 $ 1.625 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.

As of December 31, 2023, all of the restricted net assets of Vistra Operations may be distributed to Parent.

In addition to the restrictions under the Vistra Operations Credit Agreement, under applicable Delaware law, we are only permitted to make distributions either out of "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock), or out of net profits for the fiscal year in which the distribution is declared or the prior fiscal year.

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

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, 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

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis.

We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.

Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra Chief Financial Officer.

Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance risk.

These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 17 for additional information regarding credit risk associated with our derivatives).

We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:

• Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date.

Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted.

We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that are legally characterized as settlement of derivative contracts rather than collateral.

• Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals.

We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observable.

The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors.

• Level 3 valuations use unobservable inputs for the asset or liability.

Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.

We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value.

Significant unobservable inputs used 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.

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:

December 31, 2023 December 31, 2022

3 (a) Reclass (b) Total Level

3 (a) Reclass (b) Total

Commodity contracts $ 2,886 $ 628 $ 630 $ 14 $ 4,158 $ 3,512 $ 789 $ 791 $ 13 $ 5,105

Interest rate swaps — 64 — — 64 — 135 — — 135

Nuclear decommissioning trust – equity securities (c) 638 — — — 638 532 — — — 532

Nuclear decommissioning trust – debt securities (c) — 734 — — 734 — 658 — — 658

Sub-total $ 3,524 $ 1,426 $ 630 $ 14 5,594 $ 4,044 $ 1,582 $ 791 $ 13 6,430

Assets measured at net asset value (d):

Nuclear decommissioning trust – equity securities (c) 579 458

Total assets $ 6,173 $ 6,888

Commodity contracts $ 3,815 $ 1,395 $ 1,674 $ 14 $ 6,898 $ 5,297 $ 933 $ 2,010 $ 13 $ 8,253

Interest rate swaps — 48 — — 48 — 83 — — 83

Total liabilities $ 3,815 $ 1,443 $ 1,674 $ 14 $ 6,946 $ 5,297 $ 1,016 $ 2,010 $ 13 $ 8,336

(a) See table below for description of Level 3 assets and liabilities.

(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.

(d) The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our consolidated balance sheets.

Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy.

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.

Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates.

See Note 17 for further discussion regarding derivative instruments.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility.

These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at December 31, 2023 and 2022:

December 31, 2023

Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b) Average (b)

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)

$ 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 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 )

December 31, 2022

Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b) Average (b)

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)

$ 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 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, 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.

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.

(e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM.

(f) While we use the market approach, there is insufficient market data to consider the valuation liquid.

(g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.

(h) Primarily based on the historical forward PJM and Northeast 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.

See the table below for discussion of transfers between Level 2 and Level 3 for the years ended December 31, 2023, 2022 and 2021.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the years ended December 31, 2023, 2022 and 2021.

Year Ended December 31,

2023 2022 2021

Net asset (liability) balance at beginning of period $ ( 1,219 ) $ ( 360 ) $ 22

Total unrealized valuation losses ( 765 ) ( 1,382 ) ( 53 )

Purchases, issuances and settlements (a):

Purchases 222 185 114

Issuances ( 30 ) ( 62 ) ( 36 )

Settlements 136 345 ( 314 )

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.

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

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.

We also utilize short-term electricity, natural gas, coal and emissions derivative instruments for fuel hedging and other purposes.

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

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.

See Note 12 for details on our interest rate swaps outstanding as of December 31, 2023.

Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities.

The following tables provide detail of derivative contractual assets and liabilities as reported in our consolidated balance sheets at December 31, 2023 and 2022.

Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.

December 31, 2023

Derivative Assets Derivative Liabilities

Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total

Current assets $ 3,585 $ 53 $ 7 $ — $ 3,645

Noncurrent assets 565 11 1 — 577

Current liabilities ( 1 ) — ( 5,233 ) ( 24 ) ( 5,258 )

Noncurrent liabilities ( 5 ) — ( 1,659 ) ( 24 ) ( 1,688 )

Net assets (liabilities) $ 4,144 $ 64 $ ( 6,884 ) $ ( 48 ) $ ( 2,724 )

The following is a summary of our cumulative redeemable preferred stock outstanding.

In the event of liquidation or dissolution of the Company, the payment of dividends and the distribution of assets to preferred stockholders takes precedence over the Company's common stockholders.

Preferred Stock Series

Shares Issued and Outstanding (a)

Earliest Redemption Date (b)

Date at Which Dividend Rate Becomes Floating

Floating Annual Rates

1,000,000 8.000 % October 15,

Treasury rate (subject to floor of 1.07 %) plus 6.93 %

1,000,000 7.000 % December 15,

Derivative Assets Derivative Liabilities

Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total

Current assets $ 4,442 $ 92 $ 4 $ — $ 4,538

Noncurrent assets 656 43 3 — 702

Current liabilities ( 1 ) — ( 6,562 ) ( 47 ) ( 6,610 )

Noncurrent liabilities ( 5 ) — ( 1,685 ) ( 36 ) ( 1,726 )

Net assets (liabilities) $ 5,092 $ 135 $ ( 8,240 ) $ ( 83 ) $ ( 3,096 )

The following table presents the pre-tax effect of derivative gains (losses) on net income, including realized and unrealized effects.

Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.

Year Ended December 31,

Derivative (consolidated statements of operations presentation) 2023 2022 2021

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

We elect to report derivative assets and liabilities in our consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives.

We maintain standardized master netting agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce credit exposure between us and the counterparty.

These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.

Generally, margin deposits that contractually offset these derivative instruments are reported separately in our consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral.

Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.

The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:

December 31, 2023 December 31, 2022

Derivative Assets

and Liabilities Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts Derivative Assets

and Liabilities Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts

Derivative assets:

Commodity contracts $ 4,144 $ ( 3,519 ) $ ( 26 ) $ 599 $ 5,092 $ ( 4,480 ) $ ( 20 ) $ 592

Interest rate swaps 64 ( 28 ) — 36 135 ( 64 ) — 71

Total derivative assets 4,208 ( 3,547 ) ( 26 ) 635 5,227 ( 4,544 ) ( 20 ) 663

Derivative liabilities:

Commodity contracts ( 6,884 ) 3,519 970 ( 2,395 ) ( 8,240 ) 4,480 1,675 ( 2,085 )

Interest rate swaps ( 48 ) 28 — ( 20 ) ( 83 ) 64 — ( 19 )

Total derivative liabilities ( 6,932 ) 3,547 970 ( 2,415 ) ( 8,323 ) 4,544 1,675 ( 2,104 )

Net amounts $ ( 2,724 ) $ — $ 944 $ ( 1,780 ) $ ( 3,096 ) $ — $ 1,655 $ ( 1,441 )

(a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.

(b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes by commodity, excluding those derivatives that qualified for the NPNS or other scope exceptions permitted by ASC 815, Derivatives and Hedging as of December 31, 2023 and 2022:

December 31, 2023 December 31, 2022

Derivative type Notional Volume Unit of Measure

Natural gas (a) 5,335 6,007 Million MMBtu

Electricity 800,001 754,762 GWh

Financial transmission rights (b) 250,895 225,845 GWh

Coal 35 48 Million U.S.

Fuel oil 3 105 Million gallons

Emissions 24 40 Million U.S.

Renewable energy certificates 29 31 Million certificates

Interest rate swaps – variable/fixed (c) $ 5,225 $ 6,720 Million U.S.

Interest rate swaps - fixed/variable (c) $ 1,300 $ 2,120 Million U.S.

(a) Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.

(b) Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions.

Credit Risk-Related Contingent Features of Derivatives

Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:

Fair value of derivative contract liabilities (a) $ ( 1,890 ) $ ( 1,934 )

Offsetting fair value under netting arrangements (b) 692 899

Cash collateral and letters of credit 854 253

Liquidity exposure $ ( 344 ) $ ( 782 )

(b) Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.

Concentrations of Credit Risk Related to Derivatives

We have concentrations of credit risk with the counterparties to our derivative contracts.

As of December 31, 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 $ 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.

Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings.

However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity.

The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.

We maintain credit risk policies with regard to our counterparties to minimize overall credit risk.

These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty.

Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized.

Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty.

The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances.

An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS

Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries.

Oncor is a participant in the Retirement Plan.

After amendments in 2012, employees in the Retirement Plan now consist entirely of participants who were active and retired collective bargaining unit employees.

The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA.

The Retirement Plan provides benefits to participants under one of two formulas:

Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.

It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations.

The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service.

As Vistra accounts for its interest in this OPEB plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the OPEB information presented below.

In addition, Vistra is the sponsor of OPEB plans that certain EFH Corp.

and Dynegy retirees participate in.

Pension and OPEB Costs

Treasury rate (subject to floor of 1.26 %) plus 5.74 %

476,066 8.875 % January 15,

Treasury rate (subject to floor of 3.83 %) plus 5.045 %

(a) Series C Preferred Stock issued totaled 476,081 shares at December 31, 2023.

(b) Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.

Each series of preferred stock has a liquidation price of $ 1,000 , plus accrued and unpaid dividends through their redemption date.

Preferred stock is not convertible into or exchangeable for any other securities of the Company and has limited voting rights.

Preferred Stock Dividends

Preferred stock dividends are payable semiannually in arrears when declared by the Board.

The following table summarizes preferred stock dividends paid per share in the years ended December 31, 2024, 2023, and 2022.

Year Ended December 31,

Preferred Stock Series

2024 2023 2022

Pension costs $ 9 $ 2 $ 6

OPEB costs 5 4 8

Total benefit costs recognized as expense $ 14 $ 6 $ 14

Market-Related Value of Assets Held in Pension Benefit Trusts

We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs.

We include all gains or losses in the market-related value of assets over a rolling four-year period.

Each year, 25 % of such gains and losses for the current year and for each of the preceding three years is included in the market-related value.

Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.

Detailed Information Regarding Pension Plans and OPEB Benefits

The following information is based on a December 31, 2023, 2022 and 2021 measurement dates:

Retirement Plan OPEB Plans

Year Ended December 31, Year Ended December 31,

Series A Preferred Stock

$ 80.00 $ 80.00 $ 80.00

Assumptions Used to Determine Net Periodic Pension and Benefit Cost:

Discount rate 5.16 % 2.84 % 2.50 % 5.18 % 2.87 % 2.51 %

Expected rate of compensation increase 3.79 % 3.49 % 3.41 %

Interest crediting rate for cash balance 3.00 % 3.00 % 3.00 %

Expected return on plan assets (Vistra Plan) 5.85 % 4.24 % 3.77 %

Expected return on plan assets (Dynegy Plan) 5.85 % 4.77 % 4.42 %

Expected return on plan assets (EEI Plan) — % 4.92 % 4.72 %

Expected return on plan assets (EEI Union) 3.89 % 3.92 % 6.79 %

Expected return on plan assets (EEI Salaried) 4.85 % 3.41 % 2.95 %

Components of Net Pension and Benefit Cost:

Service cost $ 3 $ 4 $ 5 $ 1 $ 1 $ 1

Interest cost 21 17 16 5 4 4

Expected return on assets ( 18 ) ( 19 ) ( 18 ) ( 1 ) ( 1 ) ( 2 )

Amortization of unrecognized amounts, net 3 — 3 — — 5

Net periodic pension and OPEB cost $ 9 $ 2 $ 6 $ 5 $ 4 $ 8

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:

Net (gain) loss $ 7 $ ( 16 ) $ ( 27 ) $ — $ ( 22 ) $ ( 10 )

Prior service (credit) cost ( 6 ) 9 — — — ( 2 )

Curtailment and settlements — — ( 2 ) — — —

Total recognized in net periodic benefit cost and other comprehensive income $ 10 $ ( 5 ) $ ( 23 ) $ 5 $ ( 18 ) $ ( 4 )

Assumptions Used to Determine Benefit Obligations at Period End:

Discount rate 4.97 % 5.16 % 2.84 % 4.98 % 5.18 % 2.87 %

Expected rate of compensation increase 3.64 % 3.79 % 3.49 %

Interest crediting rate for cash balance plans 3.50 % 3.00 % 3.00 %

Net Actuarial Gains (Losses)

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, 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

Year Ended December 31, Year Ended December 31,

Series B Preferred Stock

$ 70.00 $ 70.00 $ 70.97

Change in Pension and Postretirement Benefit Obligations:

Projected benefit obligation at beginning of period $ 449 $ 605 $ 110 $ 146

Service cost 3 4 1 1

Interest cost 21 17 5 4

Participant contributions — — 3 2

Plan amendments 1 9 — —

Actuarial (gain) loss 10 ( 113 ) 1 ( 30 )

Benefits paid ( 59 ) ( 73 ) ( 12 ) ( 13 )

Projected benefit obligation at end of year $ 425 $ 449 $ 108 $ 110

Accumulated benefit obligation at end of year $ 422 $ 447 $ — $ —

Change in Plan Assets:

Fair value of assets at beginning of period $ 320 $ 470 $ 29 $ 39

Employer contributions — — 9 9

Participant contributions — — 3 2

Actual gain (loss) on assets 24 ( 77 ) 2 ( 6 )

Transfers — — ( 19 ) ( 2 )

Benefits paid ( 59 ) ( 73 ) ( 12 ) ( 13 )

Fair value of assets at end of year $ 285 $ 320 $ 12 $ 29

Funded Status:

Projected benefit obligation $ ( 425 ) $ ( 449 ) $ ( 108 ) $ ( 110 )

Fair value of assets 285 320 12 29

Funded status at end of year $ ( 140 ) $ ( 129 ) $ ( 96 ) $ ( 81 )

Amounts Recognized in the Balance Sheet Consist of:

Investments $ — $ — $ 3 $ 20

Other current liabilities — — ( 9 ) ( 8 )

Other noncurrent liabilities ( 140 ) ( 129 ) ( 90 ) ( 93 )

Net liability recognized $ ( 140 ) $ ( 129 ) $ ( 96 ) $ ( 81 )

Amounts Recognized in Accumulated Other Comprehensive Income Consist of:

Net actuarial (gain) loss $ 4 $ ( 4 ) $ ( 15 ) $ ( 15 )

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, 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:

Interest-bearing cash (a) $ — $ 2

Cash commingled trusts 4 4

Equity securities:

Global equities 82 80

Fixed income securities:

Corporate bonds (b) 82 107

Government bonds 54 44

Other (c) 18 24

Real estate 28 43

Hedge funds 17 16

Total assets measured at net asset value $ 285 $ 320

(a) Interest -bearing cash is classified as Level 2.

(b) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.

(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.

Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO) in Excess of Plan Assets

The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets.

Pension Plans with PBO and ABO in Excess of Plan Assets:

Projected benefit obligations $ 425 $ 449

Accumulated benefit obligation $ 422 $ 447

Plan assets $ 285 $ 320

Retirement Plan Investment Strategy and Asset Allocations

Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S.

Treasuries and agency securities and money market instruments.

Equity securities are held to enhance returns by participating in a wide range of investment opportunities.

International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets.

Real estate, hedge funds and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential.

The target asset allocation ranges of pension plan investments by asset category are as follows:

Target Allocation Ranges

Asset Category:

Vistra Plan Dynegy Plan

Fixed income securities 50 % - 70 % 40 % - 50 %

Global equity securities 20 % - 28 % 28 % - 38 %

Real estate 6 % - 10 % 7 % - 15 %

Credit strategies 2 % - 6 % 4 % - 8 %

Hedge funds 2 % - 6 % 4 % - 8 %

Retirement Plan Expected Long-Term Rate of Return on Assets Assumption

Retirement Plan

Expected Long-Term Rate of Return

Vistra Plan Dynegy Plan

Fixed income securities 5.3 % 5.1 %

Global equity securities 7.4 % 7.4 %

Real estate 5.5 % 5.5 %

Credit strategies 6.5 % 6.5 %

Hedge funds 7.3 % 7.3 %

Weighted average 5.9 % 6.1 %

Benefit Plan Assumed Health Care Cost Trend Rates

The following tables provide information regarding the assumed health care cost trend rates.

Assumed Health Care Cost Trend Rates-Not Medicare Eligible:

Health care cost trend rate assumed for next year 7.00 % 6.80 %

Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 %

Year that the rate reaches the ultimate trend rate 2033 2032

Assumed Health Care Cost Trend Rates-Medicare Eligible:

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 %

Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 %

Year that the rate reaches the ultimate trend rate 2033 2032

Significant Concentrations of Risk

The plans' investments are exposed to risks such as interest rate, capital market and credit risks.

While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so.

Assumed Discount Rate

We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2023 consisted of 509 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings.

Contributions

Contributions to the Retirement Plan for the years ended December 31, 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

Estimated future benefit payments to beneficiaries are as follows:

Series C Preferred Stock

In October 2024, the Board declared a semi-annual dividend of $ 44.375 per share of Series C Preferred Stock that was paid in January 2025.

In February 2025, the Board declared a semi-annual dividend of $ 40.00 per share of Series A Preferred Stock that will be paid in April 2025.

EARNINGS PER SHARE

Basic earnings per share available to common stockholders are based on the weighted average number of common shares outstanding during the period.

Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.

Year Ended December 31,

2024 2023 2022

Pension benefits $ 52 $ 30 $ 36 $ 37 $ 29 $ 142

OPEB $ 10 $ 9 $ 9 $ 9 $ 8 $ 37

Qualified Savings Plans

Our employees may participate in a qualified savings plan (the Thrift Plan).

This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA.

Employees who earn more than such threshold may contribute from 1 % to 20 % of their regular salary or wages.

Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options.

Aggregate employer contributions to the qualified savings plans totaled $ 33 million, $ 33 million and $ 34 million for the years ended December 31, 2023, 2022 and 2021, respectively.

(in millions, except share data)

Net income (loss) attributable to Vistra $ 2,659 $ 1,493 $ ( 1,227 )

Less cumulative dividends attributable to Series A Preferred Stock ( 80 ) ( 80 ) ( 80 )

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

Less cumulative dividends attributable to Series C Preferred Stock ( 42 ) — —

Net income (loss) attributable to common stock — basic and diluted 2,467 1,343 ( 1,377 )

Weighted average shares of common stock outstanding:

Basic 344,788,634 369,771,359 422,447,074

Dilutive securities:

Stock-based incentive compensation plan 7,778,426 5,421,752 —

Diluted 352,567,060 375,193,110 422,447,074

Net income (loss) per weighted average share of common stock outstanding:

Basic $ 7.16 $ 3.63 $ ( 3.26 )

Diluted $ 7.00 $ 3.58 $ ( 3.26 )

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive were immaterial in the year ended December 31, 2024 and were 392,218 and 8,292,647 shares for the years ended December 31, 2023 and 2022, respectively.

STOCK-BASED COMPENSATION

1 unchanged sentence

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 .

Following approval of the Board and approval by the stockholders at the 2019 and 2024 annual meetings of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000 and 43,000,000 , respectively.

The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things:

10 unchanged sentences

2024 2023 2022

(in millions)

Total stock-based compensation expense $ 100 $ 77 $ 65

2 unchanged sentences

Stock Options

The fair value of each stock option is estimated on the date of grant using a Black-Scholes option-pricing model.

The risk-free interest rate used in the option valuation model was based on yields available on the grant dates for U.S.

Treasury Strips with maturity consistent with the expected life assumption.

The expected term of the option represents the period of time that options granted are expected to be outstanding and is based on the SEC Simplified Method (midpoint of average vesting time and contractual term).

Expected volatility is based on an average of the historical, daily volatility of a peer group selected by Vistra over a period consistent with the expected life assumption ending on the grant date.

We assumed a 2.3 % dividend yield in the valuation of options granted in 2020.

These options may be exercised over a three year graded vesting period and will expire 10 years from the grant date.

No options were issued in 2021, 2022, or 2023.

Stock options outstanding at December 31, 2024 are all held by current or former employees.

6 unchanged sentences

Exercised ( 2,526 ) $ 20.06

Forfeited or expired ( 90 ) $ 21.68

Total outstanding at end of period 3,600 $ 19.97 3.5 $ 424.4

Exercisable at December 31, 2024 3,600 $ 19.97 3.5 $ 424.4

As of December 31, 2023, there was no unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan.

As of December 31, 2024, there was no unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan and no new options were issued in the three years ended December 31, 2024.

Restricted Stock Units

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As of December 31, 2024, $ 61 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2.0 years.

Performance Stock Units

We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis.

2 unchanged sentences

As of December 31, 2024, we have $ 64 million of unrecognized compensation cost associated with PSUs.

RELATED PARTY TRANSACTIONS

In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.

Registration Rights Agreement

Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the RRA) with certain selling stockholders.

Pursuant to the RRA, we maintain a registration statement on Form S-3 providing for registration of the resale of the Vistra common stock held by such selling stockholders.

In addition, under the terms of the RRA, among other things, if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the RRA the opportunity to register all or part of their shares on the terms and conditions set forth in the RRA.

Tax Receivable Agreement

On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH.

See Note 8 for discussion of the TRA.

SEGMENT INFORMATION

The operations of Vistra are aligned into six reportable business segments:

(i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure.

The operations of Vistra are aligned into five reportable business segments:

(i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure.

In the fourth quarter of 2024, we updated our reportable segments to reflect changes in how the Company's CODM makes operating decisions, assesses performance, and allocates resources by removing the Sunset segment.

The results of the plants previously included in the Sunset segment are now reflected in the Texas and East segments based on their respective geography.

Our Chief Executive Officer is our CODM.

2 unchanged sentences

The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial and industrial customers.

Substantially all of these activities are conducted by TXU Energy, Ambit, Dynegy Energy Services, Homefield Energy and U.S.

Gas & Electric across 19 states in the U.S.

The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management.

The Texas segment represents results from Vistra's electricity generation operations in the ERCOT market, other than assets that are now part of the Sunset or Asset Closure segments.

Substantially all of these activities are conducted by TXU Energy, Ambit, Dynegy Energy Services, Homefield Energy, Energy Harbor, and U.S.

Gas & Electric across 16 states and the District of Columbia.

The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel procurement, and logistics management.

The Texas segment represents results from all of Vistra's electricity generation operations in the ERCOT market except for assets included in the Asset Closure segments.

The East segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S.

electric grid, other than assets that are now part of the Sunset or Asset Closure segments, and includes operations in the PJM, ISO-NE and NYISO markets.

We determined it was appropriate to aggregate results from these markets into one reportable segment, East, given similar economic characteristics.

The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site (see Note 3).

The Sunset segment consists of generation plants with announced retirement dates after December 31, 2023.

Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments.

We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement dates after December 31, 2023.

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 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.

electric grid, other than assets included in the Asset Closure segment, and includes operations in the PJM, MISO, ISO-NE, and NYISO markets.

The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 6 for additional information).

Upon movement of generation plant assets to the Asset Closure segment, prior year results are retrospectively adjusted, if the effects are material, for comparative purposes.

Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines.

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.

Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses not allocated to our operating segments.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1.

3 unchanged sentences

Adjusted EBITDA is most comparable to consolidated Net income (loss) prepared based on U.S.

The CODM uses net income in competitive analysis by benchmarking to the Company's competitors and in evaluating drivers of segment profits available to the Company's equity holders.

We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices.

Certain shared services costs are allocated to the segments.

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

Eliminations Consolidated

Substantially all income tax (expense) benefit is recognized in Corporate and Other.

Year Ended December 31, 2024

Asset Closure

Total Reportable Segments

Corporate and Other

(in millions)

Operating revenues

December 31, 2023 $ 10,572 $ 3,823 $ 4,215 $ 914 $ 1,831 $ — $ 2 $ ( 6,578 ) $ 14,779

December 31, 2022 9,455 3,733 3,706 336 868 384 1 ( 4,755 ) 13,728

December 31, 2021 7,871 2,790 2,587 374 661 78 — ( 2,284 ) 12,077

$ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ 24,730 $ ( 7,506 ) $ 17,224

Fuel, purchased power costs, and delivery fees

( 10,276 ) ( 1,596 ) ( 2,698 ) ( 221 ) ( 3 ) ( 14,794 ) 7,509 ( 7,285 )

Operating costs

( 159 ) ( 996 ) ( 1,103 ) ( 72 ) ( 81 ) ( 2,411 ) ( 3 ) ( 2,414 )

Selling, general, and administrative expenses

( 977 ) ( 169 ) ( 148 ) ( 25 ) ( 43 ) ( 1,362 ) ( 239 ) ( 1,601 )

Other segment items:

Depreciation and amortization

December 31, 2023 $ ( 102 ) $ ( 544 ) $ ( 647 ) $ ( 79 ) $ ( 62 ) $ — $ ( 68 ) $ — $ ( 1,502 )

December 31, 2022 ( 145 ) ( 537 ) ( 706 ) ( 42 ) ( 66 ) ( 31 ) ( 69 ) — ( 1,596 )

December 31, 2021 ( 212 ) ( 608 ) ( 698 ) ( 60 ) ( 94 ) ( 45 ) ( 36 ) — ( 1,753 )

Operating income (loss):

December 31, 2023 $ 443 $ 300 $ 1,158 $ 425 $ 639 $ ( 111 ) $ ( 193 ) $ — $ 2,661

December 31, 2022 1,172 ( 711 ) ( 867 ) ( 250 ) ( 228 ) ( 158 ) ( 135 ) — ( 1,177 )

December 31, 2021 2,213 ( 2,601 ) ( 552 ) ( 8 ) ( 67 ) ( 417 ) ( 83 ) — ( 1,515 )

Interest expense and related charges:

December 31, 2023 $ ( 20 ) $ 21 $ — $ 8 $ ( 2 ) $ ( 5 ) $ ( 742 ) $ — $ ( 740 )

December 31, 2022 ( 14 ) 20 ( 3 ) 6 ( 3 ) ( 3 ) ( 371 ) — ( 368 )

December 31, 2021 ( 9 ) 14 ( 15 ) 9 ( 3 ) — ( 381 ) 1 ( 384 )

Income tax (expense) benefit:

December 31, 2023 $ — $ — $ ( 1 ) $ — $ — $ — $ ( 507 ) $ — $ ( 508 )

December 31, 2022 — — — — — — 350 — 350

December 31, 2021 ( 2 ) — — — — — 460 — 458

( 114 ) ( 581 ) ( 996 ) ( 86 ) — ( 1,777 ) ( 66 ) ( 1,843 )

Interest expenses and related charges ( 54 ) 46 9 1 ( 4 ) ( 2 ) ( 898 ) ( 900 )

Income tax expense — — — — — — ( 655 ) ( 655 )

( 1 ) 35 177 ( 3 ) 14 222 64 286

Net income (loss)

December 31, 2023 $ 424 $ 354 $ 1,160 $ 454 $ 633 $ ( 6 ) $ ( 1,527 ) $ — $ 1,492

December 31, 2022 1,158 ( 615 ) ( 868 ) ( 238 ) ( 230 ) ( 147 ) ( 270 ) — ( 1,210 )

December 31, 2021 2,196 ( 2,512 ) ( 567 ) 1 ( 61 ) ( 374 ) 53 — ( 1,264 )

Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:

December 31, 2023 $ 1 $ 500 $ 105 $ 18 $ 69 $ — $ 58 $ — $ 751

December 31, 2022 1 335 56 116 33 — 55 — 596

December 31, 2021 1 266 44 8 28 3 48 — 398

(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

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.

The impairment is reported in our Sunset segment and includes write-downs of property, plant and equipment of $ 71 million and write-downs of inventory of $ 3 million.

In the second quarter of 2021, we recognized an impairment loss of $ 38 million related to our Zimmer generation facility in Ohio as a result of a significant decrease in the estimated useful life of the facility, reflecting a decrease in the economic forecast of the facility and the inability to secure capacity revenues for the plant in the PJM capacity auction held in May 2021.

The impairment is reported in our Asset Closure segment and includes write-downs of property, plant and equipment of $ 33 million and write-downs of inventory of $ 5 million.

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

$ 1,216 $ 2,133 $ 902 $ 471 $ ( 116 ) $ 4,606 $ ( 1,794 ) $ 2,812

Capital expenditures, including nuclear fuel and excluding growth expenditures

$ 4 $ 1,124 $ 661 $ 70 $ — $ 1,859 $ 58 $ 1,917

Year Ended December 31, 2023

Asset Closure (b)

Total Reportable Segments

Corporate and Other

(in millions)

Operating revenues

$ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ 21,355 $ ( 6,576 ) $ 14,779

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 (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.

Fuel, purchased power costs, and delivery fees

( 9,046 ) ( 2,028 ) ( 2,730 ) ( 328 ) ( 3 ) ( 14,135 ) 6,578 ( 7,557 )

Operating costs

( 123 ) ( 917 ) ( 528 ) ( 58 ) ( 74 ) ( 1,700 ) ( 2 ) ( 1,702 )

Selling, general, and administrative expenses

( 858 ) ( 140 ) ( 127 ) ( 24 ) ( 34 ) ( 1,183 ) ( 125 ) ( 1,308 )

Other segment items:

Depreciation and amortization

( 102 ) ( 550 ) ( 703 ) ( 79 ) — ( 1,434 ) ( 68 ) ( 1,502 )

Interest expenses and related charges ( 20 ) 21 ( 2 ) 8 ( 5 ) 2 ( 742 ) ( 740 )

Income tax expense — — ( 1 ) — — ( 1 ) ( 507 ) ( 508 )

1 33 ( 50 ) 21 110 115 ( 85 ) 30

Net income (loss)

$ 424 $ 398 $ 1,749 $ 454 $ ( 6 ) $ 3,019 $ ( 1,527 ) $ 1,492

Capital expenditures, including nuclear fuel and excluding growth expenditures

$ 1 $ 750 $ 362 $ 366 $ — $ 1,479 $ 58 $ 1,537

Year Ended December 31, 2022

Asset Closure (b)

Total Reportable Segments

Corporate and Other

(in millions)

Operating revenues

$ 9,455 $ 3,878 $ 4,429 $ 336 $ 384 $ 18,482 $ ( 4,754 ) $ 13,728

Fuel, purchased power costs, and delivery fees

( 7,169 ) ( 3,052 ) ( 4,132 ) ( 481 ) ( 322 ) ( 15,156 ) 4,755 ( 10,401 )

Operating costs

( 143 ) ( 832 ) ( 482 ) ( 42 ) ( 145 ) ( 1,644 ) ( 1 ) ( 1,645 )

Selling, general, and administrative expenses

( 826 ) ( 135 ) ( 97 ) ( 21 ) ( 44 ) ( 1,123 ) ( 66 ) ( 1,189 )

Other segment items:

Interest expenses and related charges ( 14 ) 20 ( 6 ) 6 ( 3 ) 3 ( 371 ) ( 368 )

Depreciation and amortization

( 145 ) ( 541 ) ( 768 ) ( 42 ) ( 31 ) ( 1,527 ) ( 69 ) ( 1,596 )

Income tax benefit — — — — — — 350 350

— 76 ( 71 ) 6 14 25 ( 114 ) ( 89 )

Net income (loss)

$ 1,158 $ ( 586 ) $ ( 1,127 ) $ ( 238 ) $ ( 147 ) $ ( 940 ) $ ( 270 ) $ ( 1,210 )

Capital expenditures, including nuclear fuel and excluding growth expenditures

$ 1 $ 520 $ 187 $ 345 $ — $ 1,053 $ 55 $ 1,108

(a) Other includes impairment of long-lived assets, other income, other deductions, and the impacts of the Tax Receivable Agreement.

(b) We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants retired in 2022 and 2023.

See Note 6 for additional information.

SUPPLEMENTARY FINANCIAL INFORMATION

Other Income and Deductions

1 unchanged sentence

2024 2023 2022

(in millions)

Other income:

Insurance settlements (a) $ 24 $ 70 $ 88

Gain on sale of land (b) 95 8 9

Gain on TRA settlement (c) 29 — —

Gain on settlement of rail transportation disputes (d) — — 15

NDT net income (a) $ 170 $ — $ —

Insurance settlements (b) 23 24 70

Gain on sale of land (c) 6 95 8

Gain on TRA settlement (d) 10 29 —

Interest income 65 86 19

4 unchanged sentences

Total other deductions $ 21 $ 14 $ 4

(a) For the year ended December 31, 2023, $ 19 million reported in the West segment and $ 5 million in the Asset Closure segment.

(a) Includes interest, dividends, and net realized and unrealized gains and losses associated with NDTs of the PJM nuclear facilities.

Reported in the East segment.

(b) For the year ended December 31, 2024, $ 20 million reported in the Texas segment and $ 3 million reported in the West segment.

For the year ended December 31, 2023, $ 19 million reported in the West segment and $ 5 million in the Asset Closure segment.

For the year ended December 31, 2022, $ 62 million reported in the Texas segment, $ 6 million reported in the West segment, $ 1 million reported in the Asset Closure segment, and $ 1 million reported in the Corporate and Other non-segment.

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

December 31, 2023 December 31, 2022

Assets Noncurrent Assets Current

Assets Noncurrent Assets

Amounts related to remediation escrow accounts $ 40 $ 14 $ 37 $ 33

Total restricted cash $ 40 $ 14 $ 37 $ 33

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.

Trade Accounts Receivable

Wholesale and retail trade accounts receivable $ 1,735 $ 2,124

Allowance for uncollectible accounts ( 61 ) ( 65 )

Trade accounts receivable — net $ 1,674 $ 2,059

Gross trade accounts receivable as of December 31, 2023 and 2022 included unbilled retail revenues of $ 614 million and $ 607 million, respectively.

Allowance for Uncollectible Accounts Receivable

Year Ended December 31,

2023 2022 2021

Allowance for uncollectible accounts receivable at beginning of period $ 65 $ 45 $ 45

Increase for bad debt expense 164 179 110

Decrease for account write-offs ( 168 ) ( 159 ) ( 110 )

Allowance for uncollectible accounts receivable at end of period $ 61 $ 65 $ 45

For the year ended December 31, 2023, $ 94 million reported in the Asset Closure segment and $ 1 million reported in the Texas segment.

For the year ended December 31, 2022, reported in the Asset Closure segment.

(d) Reported in the Corporate and Other.

Inventories by Major Category

(in millions)

Materials and supplies $ 533 $ 289

2 unchanged sentences

Total inventories $ 970 $ 740

Nuclear decommissioning trust $ 1,951 $ 1,648

(in millions)

Nuclear decommissioning trusts $ 4,440 $ 1,951

Assets related to employee benefit plans 14 28

Land investments 42 42

Miscellaneous other 14 10

Other investments 16 14

Total investments $ 4,512 $ 2,035

Nuclear Decommissioning Trust

Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value.

Decommissioning costs are being recovered from Oncor 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 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.

A summary of the fair market value of investments in the fund follows:

Year Ended December 31,

Debt securities (a) $ 734 $ 658

Equity securities (b) 1,217 990

Total $ 1,951 $ 1,648

(a) The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's.

The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds.

The debt securities had an average coupon rate 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.

equity investments and the MSCI EAFE Index for non-U.S.

equity investments.

Debt securities held as of December 31, 2023 mature as follows:

$ 296 million in one to five years, $ 142 million in five to 10 years and $ 296 million after 10 years.

The following table summarizes proceeds from sales of securities and investments in new securities.

Year Ended December 31,

2023 2022 2021

Proceeds from sales of securities $ 601 $ 670 $ 483

Investments in securities $ ( 624 ) $ ( 693 ) $ ( 505 )

Property, Plant and Equipment

Power generation and structures $ 17,297 $ 16,597

Office and other equipment 159 163

Total 18,028 17,344

Less accumulated depreciation ( 6,657 ) ( 5,753 )

Net of accumulated depreciation 11,371 11,591

Finance lease right-of-use assets (net of accumulated depreciation) 160 173

Nuclear fuel (net of accumulated amortization of $ 120 million and $ 152 million)

Construction work in progress 522 522

Property, plant and equipment — net $ 12,432 $ 12,554

Depreciation expenses totaled $ 1.344 billion, $ 1.388 billion and $ 1.478 billion for the years ended December 31, 2023, 2022 and 2021, respectively.

Our property, plant and equipment consist of our power generation assets, related mining assets, information system hardware, capitalized corporate office lease space and other leasehold improvements.

The estimated remaining useful lives range from 1 to 30 years for our property, plant and equipment.

Asset Retirement and Mining Reclamation Obligations (ARO)

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs.

There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor.

As of 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 Land Reclamation, Coal Ash and Other Total

Liability at December 31, 2020 $ 1,585 $ 851 $ 2,436

Accretion 50 38 88

Adjustment for change in estimates (a) — 14 14

Payments — ( 88 ) ( 88 )

Liability at December 31, 2021 1,635 815 2,450

Accretion 53 34 87

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 (a) — 94 94

Payments — ( 81 ) ( 81 )

Liability at December 31, 2023 1,742 796 2,538

Less amounts due currently — ( 124 ) ( 124 )

Noncurrent liability at December 31, 2023 $ 1,742 $ 672 $ 2,414

(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.

Any remaining unpaid third-party obligation has been reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets.

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

(in millions)

Retirement and other employee benefits (Note 14)

2 unchanged sentences

Regulatory liability (b) 452 209

Operating lease liabilities 98 48

Finance lease liabilities 218 227

Uncertain tax positions, including accrued interest — 13

Liability for third-party remediation 8 17

3 unchanged sentences

(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

December 31, 2023 December 31, 2022

Long-term debt (see Note 12):

Fair Value Hierarchy Carrying Amount Fair

Value Carrying Amount Fair

Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,456 $ 2,500 $ 2,519 $ 2,486

Vistra Operations Senior Notes Level 2 11,881 11,752 9,378 8,830

Equipment Financing Agreements Level 3 65 62 74 72

We determine fair value in accordance with accounting standards as discussed in Note 16.

We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values.

Where relevant, these prices are validated through subscription services, such as Bloomberg.

(b) As of December 31, 2024, the fair value of the assets contained in the Comanche Peak NDT was higher than the carrying value of our ARO related to our nuclear generation plant decommissioning and recorded as a regulatory liability of $ 452 million and $ 209 million, respectively, in other noncurrent liabilities and deferred credits.

Supplemental Cash Flow Information

The following table reconciles cash, cash equivalents and restricted cash reported in our consolidated statements of cash flows to the amounts reported in our consolidated balance sheets at December 31, 2023 and 2022:

The following table reconciles cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows to the amounts reported in the consolidated balance sheets at December 31, 2024 and 2023:

(in millions)

Cash and cash equivalents $ 1,188 $ 3,485

Restricted cash included in current assets 40 37

Restricted cash included in noncurrent assets 14 33

Restricted cash included in current assets (a) 28 40

Restricted cash included in noncurrent assets (a) 6 14

Total cash, cash equivalents and restricted cash $ 1,222 $ 3,539

(a) Restricted cash consists of amounts related to remediation escrow accounts.

Vistra has transferred various asset retirement obligations related to several closed plant sites to a third-party remediation company.

As part of certain transfers, Vistra deposits funds into escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process.

Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits.

The following table summarizes our supplemental cash flow information for the years ended December 31, 2024, 2023, and 2022, respectively.

Non-cash investing and financing activities also includes activity related to the Energy Harbor Merger.

See Note 2 for additional information.

Year Ended December 31,

2024 2023 2022

(in millions)

Cash payments related to:

4 unchanged sentences

Accrued property, plant, and equipment additions (a) $ 258 $ 104 $ 103

Book value of nuclear fuel sold $ 26 $ — $ —

Issuance of Series C Preferred Stock as consideration for the repurchase of TRA Rights with a carrying value of $ 506 million

$ — $ 476 $ —

Book value of property, plant, and equipment sold, including nuclear fuel $ 117 $ 26 $ —

(a) Represents property, plant, and equipment accruals during the period for which cash has not been paid as of the end of the period.

For the years ended December 31, 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.

For the years ended December 31, 2024, 2023, and 2022, we paid federal income taxes of $ 5 million, zero , and $ 1 million, respectively, paid state income taxes of $ 59 million, $ 44 million, and $ 33 million, respectively, and received state tax refunds of $ 9 million, $ 13 million, and $ 8 million, respectively.

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