What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2026-02-27 compared with 2025-02-28 · 840 added, 747 removed, 1604 unchanged (50% of the section changed)

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

Critical Audit Matters

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

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

Critical Audit Matter

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

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

Fair Value Measurements — Certain Complex Level 3 Derivative Assets and Liabilities — Refer to Notes 1, 13 and 14 to the financial statements

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

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

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

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

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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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Selling, general, and administrative expenses ( 1,714 ) ( 1,601 ) ( 1,308 )

Impairment of long-lived and other assets — ( 49 ) ( 74 )

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

Other income 312 257 117

Other deductions ( 21 ) ( 14 ) ( 4 )

Impairment of long-lived assets ( 228 ) — ( 49 )

Operating income 1,906 4,081 2,661

Other income, net 394 291 243

Interest expense and related charges ( 1,179 ) ( 900 ) ( 740 )

Impacts of Tax Receivable Agreement 2 ( 5 ) ( 164 )

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

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

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

Net income before income taxes 1,123 3,467 2,000

Income tax expense ( 179 ) ( 655 ) ( 508 )

Net income 944 2,812 1,492

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

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

Net income attributable to Vistra 944 2,659 1,493

Cumulative dividends attributable to preferred stock ( 192 ) ( 192 ) ( 150 )

Net income (loss) attributable to Vistra common stock $ 2,467 $ 1,343 $ ( 1,377 )

Net income attributable to Vistra common stock $ 752 $ 2,467 $ 1,343

Weighted average shares of common stock outstanding:

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345,656,067 352,567,060 375,193,110

Net income (loss) per weighted average share of common stock outstanding:

Net income per weighted average share of common stock outstanding:

Basic $ 2.22 $ 7.16 $ 3.63

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2025 2024 2023

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

Net income $ 944 $ 2,812 $ 1,492

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

Effects related to pension and other retirement benefit obligations (net of tax expense of $ — , $ 4 and $ — )

( 3 ) 14 ( 1 )

Total other comprehensive income (loss) ( 3 ) 14 ( 1 )

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

Comprehensive income 941 2,826 1,491

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

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

Comprehensive income attributable to Vistra $ 941 $ 2,673 $ 1,492

See Notes to the Consolidated Financial Statements

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Trade accounts receivable — net 2,323 1,982

Income taxes receivable 8 6

Inventories — net

Materials and supplies

Fuel stock and natural gas in storage

Commodity and other derivative contractual assets 2,793 2,587

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Restricted cash 6 6

Investments 5,091 4,512

Property, plant, and equipment — net 19,846 18,173

18,173 12,432

Goodwill 2,810 2,807

Identifiable intangible assets — net 2,435 2,213

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Current liabilities:

Short-term borrowings $ 1,800 $ —

Accounts receivable financing 1,225 750

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Long-term debt, less amounts due currently 15,842 15,418

15,418 12,116

Forward repurchase obligation, less amounts due currently — 632

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Accumulated deferred income taxes 1,049 697

Tax Receivable Agreement obligation 14 164

Asset retirement obligations 4,035 3,936

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Total liabilities 36,440 32,187

Commitments and Contingencies

See Notes to the Consolidated Financial Statements

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(Millions of Dollars, Except Share Data)

Commitments and Contingencies

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)

Preferred stock ( 100,000,000 shares authorized, $ 1,000 liquidation preference per share, 2,476,066 shares outstanding at both December 31, 2025 and 2024, respectively)

Common stock (par value $ 0.01 per share, 1,800,000,000 shares authorized, 338,059,635 and 339,754,307 shares outstanding at December 31, 2025 and 2024, respectively)

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Cash flows — operating activities:

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

Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:

Net income $ 944 $ 2,812 $ 1,492

Adjustments to reconcile net income to cash provided by operating activities:

Depreciation and amortization 2,950 2,631 1,956

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Bad debt expense 201 183 164

Stock-based compensation 100 77 63

Stock-based compensation expense 113 100 77

Involuntary conversion gain ( 120 ) — —

Other, net ( 47 ) ( 89 ) 103

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Margin deposits, net ( 769 ) 842 1,899

Uplift securitization proceeds receivable from ERCOT — — 544

Accrued interest ( 4 ) ( 18 ) 46

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Capital expenditures, including nuclear fuel purchases and LTSA prepayments ( 2,752 ) ( 2,078 ) ( 1,676 )

Lotus acquisition (net of cash acquired) ( 1,140 ) — —

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

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Purchases of environmental allowances ( 1,189 ) ( 1,226 ) ( 1,071 )

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

Proceeds from sales of transferable ITCs 150 — —

Insurance proceeds for recovery of damaged property, plant, and equipment 325 3 15

See Notes to the Consolidated Financial Statements

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2025 2024 2023

Proceeds from sales of property, plant, and equipment, including nuclear fuel 119 196 115

Proceeds from sales of transferable ITCs — 150 —

Other, net ( 10 ) ( 6 ) ( 5 )

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Cash flows — financing activities:

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

Issuances of debt 2,506 3,817 2,498

Repayments/repurchases of debt ( 2,584 ) ( 2,287 ) ( 33 )

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

Principal payment on forward repurchase obligation ( 703 ) — —

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

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Cash used in financing activities ( 74 ) ( 1,604 ) ( 294 )

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

Cash, cash equivalents and restricted cash — beginning balance 3,539 525 1,359

Cash, cash equivalents and restricted cash — ending balance $ 1,222 $ 3,539 $ 525

Net change in cash, cash equivalents, and restricted cash (current and noncurrent) ( 400 ) ( 2,317 ) 3,014

Cash, cash equivalents, and restricted cash (current and noncurrent) — beginning balance 1,222 3,539 525

Cash, cash equivalents, and restricted cash (current and noncurrent) — ending balance $ 822 $ 1,222 $ 3,539

Supplemental Cash Flow Information:

Cash payments related to:

Interest paid

$ 1,165 $ 987 $ 636

Capitalized interest

( 125 ) ( 77 ) ( 37 )

Interest paid (net of capitalized interest)

$ 1,040 $ 910 $ 599

Non-cash investing and financing activities:

Accrued property, plant, and equipment additions (a)

$ 108 $ 258 $ 104

Issuance of Series C Preferred Stock as consideration for the repurchase of TRA Rights with a carrying value of $ 506 million

$ — $ — $ 476

See Notes to the Consolidated Financial Statements

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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 incentive compensation plans — — — 103 — — 103 — 103

Effects of stock-based incentive compensation plans (a) — — — 168 — — 168 — 168

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

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Dividends declared on preferred stock — — — — ( 150 ) — ( 150 ) — ( 150 )

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

Change in accumulated other comprehensive income — — — — — ( 1 ) ( 1 ) — ( 1 )

Other — — — ( 1 ) — — ( 1 ) — ( 1 )

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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 incentive compensation plans — — — 168 — — 168 — 168

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

Effects of stock-based incentive compensation plans (a) — — — 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 )

Change in accumulated other comprehensive income (loss) — — — — — ( 1 ) ( 1 ) — ( 1 )

Dividends to noncontrolling interest — ( 15 ) ( 15 )

Change in accumulated other comprehensive income — — — — — 14 14 — 14

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

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

Other — — — ( 8 ) ( 1 ) — ( 9 ) 10 1

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Stock repurchases ( 1,013 ) ( 1,013 ) ( 1,013 )

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

— — — — 2,659 — 2,659 102 2,761

Effects of stock-based incentive compensation plans (a) — — — 102 — — 102 — 102

Net income — — — — 944 — 944 — 944

Dividends declared on common stock — — — — ( 308 ) — ( 308 ) — ( 308 )

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

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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 )

Change in accumulated other comprehensive income — — — — — ( 3 ) ( 3 ) — ( 3 )

Other — — — ( 1 ) ( 2 ) — ( 3 ) — ( 3 )

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$ 2,476 $ 5 $ ( 6,925 ) $ 9,536 $ ( 12 ) $ 17 $ 5,097 $ 13 $ 5,110

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

(a) Includes cash payments to cover tax withholding obligations upon the vesting of stock-based incentive compensation plans of $ 52 million, $ 12 million, and $ 4 million for the years ended December 31, 2025, 2024 and 2023, respectively.

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

See Notes to the Consolidated Financial Statements

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All intercompany items and transactions have been eliminated in consolidation.

All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S.

dollars unless otherwise indicated.

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

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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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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

Government Assistance

Government Grants

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.

We account for transferable ITCs and PTCs we expect to receive by analogy to ASC 832, Government Grants as amended by Accounting Standards Update (ASU) 2025-10 (ASC 832).

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 probable, and reduces depreciation expense over the life of the asset.

See Note 5 for additional information.

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See Note 16 for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation

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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.

As of December 31, 2025 and 2024, deferred tax assets related to these credits totaled $ 69 million and $ 69 million, respectively.

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

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See Note 18 for additional information.

Cash and Cash Equivalents

Cash, Cash Equivalents and Restricted Cash

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 primarily consists of funds held in escrow accounts to fund asset retirement obligations of closed plant sites previously transferred to a third party remediation company.

Property, Plant, and Equipment

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See Note 7 for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

See Note 20 for additional information.

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

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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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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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.

See Notes 2 and 11 for additional information.

Treasury Stock

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

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.

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

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

The Company 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Accounting Standards

Accounting for Government Grants

In December 2025, the Financial Accounting Standards Board (FASB) issued ASU No.

2025-10, Government Grants (Topic 832):

Accounting for Government Grants Received by Business Entities (ASU 2025-10), which provides guidance on recognition, measurement, and presentation of government grants.

ASU 2025-10 is effective for annual periods beginning after December 15, 2028, including interim periods within those fiscal years.

Early adoption is permitted.

The Company adopted the amendments in this ASU for its fiscal year ended December 31, 2025.

The adoption did not have a material impact on the consolidated financial statements as we previously accounted for ITCs and PTCs by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance , which the FASB largely leveraged in developing the ASU.

Derivatives Scope Refinements

In September 2025, the FASB issued ASU No.

2025-07 (ASU 2025-07), Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606) .

The amendments in the ASU exclude from derivative accounting certain non-exchange-traded contracts with underlyings that are based on operations or activities specific to one of the parties to the contract.

The amendments also clarify that an entity should apply the guidance in Topic 606, including the guidance on non-cash consideration, to a contract with share-based non-cash consideration from a customer for the transfer of goods or services.

The amendments are effective for fiscal years beginning after December 15, 2026, with early adoption permitted.

The Company adopted the amendments in ASU 2025-07 prospectively for its fiscal year ended December 31, 2025 which resulted in certain wholesale contracts being excluded from derivative accounting.

Improvements to Income Tax Disclosures

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

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

Early adoption is permitted.

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

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

The Company adopted ASU 2023-09 for its fiscal year ended December 31, 2025 and applied the new disclosure requirements in Note 6 on a retrospective basis.

Expense Disaggregation Disclosures

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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.

Debt, Credit Facilities, and Financing

Vistra Operations Senior Secured Notes — In January 2026, Vistra Operations issued $ 2.25 billion aggregate principal amount of senior secured notes, consisting of $ 1.0 billion aggregate principal amount of 4.700 % senior secured notes due 2031 and $ 1.25 billion aggregate principal amount of 5.350 % senior secured notes due 2036 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

See Note 11 for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cogentrix Transaction

On December 31, 2025, Vistra executed definitive agreements to acquire Cogentrix Energy which consists of 10 modern natural gas generation facilities totaling approximately 5,500 MW of capacity (Cogentrix Transaction).

The facilities include three combined cycle gas turbine facilities and two combustion turbine facilities located across PJM, four combined cycle gas turbine facilities in ISO-NE, and one cogeneration facility in ERCOT.

Aggregate consideration at closing will consist of approximately (i) $ 2.3 billion in cash, net of adjustments for the assumption of an estimated $ 1.5 billion of outstanding indebtedness of Cogentrix as of the closing date, and (ii) 5,000,000 shares of Vistra common stock, par value $ 0.01 , to be issued to the seller, at a mutually agreed-upon value of $ 185 per share.

Consummation of the Cogentrix Transaction is subject to customary closing conditions, including receipt of all requisite regulatory approvals, including approvals of FERC and the expiration or termination of all applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

The Cogentrix Transaction is expected to close in mid-to-late 2026.

Lotus Acquisition

On October 22, 2025, pursuant to a purchase and sale agreement dated May 15, 2025, Vistra Operations acquired 100 % of the membership interests of certain subsidiaries of Lotus (Lotus Acquisition).

The Lotus Acquisition resulted in the addition of seven natural gas generation facilities totaling 2,600 MW in Delaware and Pennsylvania (PJM), Rhode Island (ISO-NE), New York (NYISO), and California (CAISO), further geographically diversifying Vistra's natural gas fleet.

The aggregate purchase price consisted of a base purchase price of $ 1.9 billion, subject to certain customary adjustments, including the acquired companies' working capital, cash, indebtedness, and certain other adjustments.

Vistra Operations funded the Lotus Acquisition with a combination of cash and the assumption of the acquired companies' indebtedness which consisted of a senior secured credit facility, including an existing term loan with approximately $ 800 million principal outstanding, which reduced the cash consideration payable at closing.

Cash consideration payable at closing, excluding adjustments for the acquired companies' working capital, cash, and certain other adjustments, was $ 1.1 billion.

The Lotus Acquisition 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 acquisition date.

The total consideration transferred at closing, inclusive of adjustments to the base purchase price, was $ 1.237 billion as determined in accordance with ASC 805, which is subject to a final true-up.

The combined results of operations are reported in the consolidated financial statements beginning as of the acquisition date.

In November 2025, the Company borrowed $ 800 million under the Commodity-Linked Credit Agreement (see Note 11 for additional information) to repay the approximately $ 800 million of debt assumed by the Company.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Provisional fair value measurements were made for acquired assets and liabilities in the fourth quarter of 2025.

Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of 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 the assets acquired and liabilities assumed are as follows:

Lotus Acquisition

Fair Value as of

October 22, 2025

(in millions)

Cash and cash equivalents $ 97

Trade accounts receivables, inventories, prepaid expenses, and other current assets 72

Property, plant, and equipment (a)

Other noncurrent assets 22

Total identifiable assets acquired 2,537

Trade accounts payable and other current liabilities 21

Long-term debt, including amounts due currently 803

Commodity and other derivative contractual liabilities (b)

Asset retirement obligations

Identifiable intangible liabilities 23

Other noncurrent liabilities and deferred credits 23

Total identifiable liabilities assumed 1,300

Net assets acquired $ 1,237

(a) 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).

(b) Acquired derivatives are valued using the methods described in Note 13 (Level 1, Level 2, or Level 3).

The following unaudited pro forma financial information for the Company for the years ended December 31, 2025 and 2024 assumes that the Lotus Acquisition occurred on January 1, 2024.

The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Lotus Acquisition been completed on January 1, 2024, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.

Lotus Acquisition

Year Ended December 31,

(in millions)

Revenues $ 18,256 $ 17,626

Net income $ 943 $ 2,787

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, effects of the Lotus Acquisition on tax expense (benefit), and other related adjustments.

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

Acquisition-related costs incurred in the Lotus Acquisition totaled $ 17 million for the year ended December 31, 2025 and are classified as selling, general, and administrative expenses in the consolidated statements of operations.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

On March 1, 2024, pursuant to a transaction agreement (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).

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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:

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

Consideration

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

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:

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, and 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Provisional fair value measurements were made for acquired assets and liabilities in the first quarter of 2024 and adjustments to those measurements were made through March 1, 2025 (the end of the measurement period).

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

Energy Harbor Merger

Fair Value as of

March 1, 2024

Measurement Period Adjustments recorded through December 31, 2024

March 1, 2024 Measurement Period Adjustments

(in millions)

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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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following unaudited pro forma financial information for the Company 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.

Energy Harbor Merger

Year Ended December 31,

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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-related costs incurred in the Energy Harbor Merger totaled $ 25 million for the year ended December 31, 2024 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 contained certain closing conditions outside our control that represented conditional redemption obligations that required us to reflect the transaction as redeemable noncontrolling interest within the mezzanine section of the consolidated balance sheet as of September 30, 2024.

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

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

The transaction closed on December 31, 2024, with all closing conditions met.

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

See Note 11 for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenue Disaggregation

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Year Ended December 31, 2025

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

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

(in millions)

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Retail energy charge in ERCOT $ 8,966 $ — $ — $ — $ — $ — $ 8,966

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

Retail energy charge in Northeast/Midwest 4,059 — — — — — 4,059

Wholesale generation revenue from ISO/RTO — 464 2,626 98 — — 3,188

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

Capacity revenue from ISO/RTO (a) — — 227 — — — 227

Revenue from other wholesale contracts — 454 458 230 4 — 1,146

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Other revenues:

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

Transferable PTC revenues (b) — 229 — — — — 229

Hedging revenues — realized 1,210 ( 440 ) ( 303 ) 116 — — 583

Hedging revenue — unrealized ( 2 ) 182 ( 826 ) ( 122 ) 2 — ( 766 )

Business interruption insurance proceeds — 47 — — 71 — 118

Intangible amortization and other revenues — ( 2 ) ( 13 ) — — 3 ( 12 )

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

Intersegment sales (c) 107 4,419 4,005 3 ( 3 ) ( 8,531 ) —

Total other revenues 1,315 4,435 2,863 ( 3 ) 70 ( 8,528 ) 152

Total revenues $ 14,340 $ 5,353 $ 6,174 $ 325 $ 74 $ ( 8,528 ) $ 17,738

(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.

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

The East segment includes $ 793 million of capacity sold offset by $ 566 million of capacity purchased.

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.

Net capacity purchased in each ISO/RTO, as applicable, included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $ 130 million offset by $ 63 million of capacity sold within the East segment.

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

(c) East segment includes $ 147 million of intersegment unrealized net losses, and Texas segment includes $ 293 million of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31, 2024

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

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

(in millions)

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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 1,351 221 7 — 1,978

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

Capacity revenue from ISO/RTO (b)

— — 74 — — — 74

Revenue from other wholesale contracts — 422 398 199 31 — 1,050

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Other revenues:

Transferable PTC revenues (b)

Transferable PTC revenues (c)

— 292 264 — — — 556

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

1,063 ( 885 ) 43 67 ( 36 ) — 252

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

191 ( 714 ) 958 243 36 — 714

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

2 — ( 5 ) — — 2 ( 1 )

Intersegment sales (c)

Intersegment sales (d)

64 4,034 3,404 6 — ( 7,508 ) —

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Total revenues $ 12,797 $ 5,394 $ 5,661 $ 839 $ 39 $ ( 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.

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.

Net capacity purchased in each ISO/RTO, as applicable, 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31, 2023

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

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

(in millions)

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Other revenues:

Hedging revenues — realized

Transferable PTC revenues

— 10 — — — — 10

Hedging revenues — realized 1,063 ( 885 ) 43 64 ( 33 ) — 252

Hedging revenue — unrealized 191 ( 714 ) 958 243 36 — 714

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

Intangible amortization and other revenues 2 — ( 5 ) — — 2 ( 1 )

2 — ( 6 ) — — — ( 4 )

Intersegment sales (b)

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

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

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.

Net capacity purchased in each ISO/RTO, as applicable, 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) 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.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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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).

• Transferable production tax credit revenues accounted for as grants related to income by analogy to ASC 832 (see Note 5 for additional information).

• Intangible amortization of acquired intangible liabilities related to retail and wholesale contracts (see Note 9 for additional information).

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Sales taxes are not included in revenue.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Performance Obligations

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.

As of December 31, 2025, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or capacity contracts with customers for which the total consideration is fixed and determinable at contract execution.

Capacity revenues are recognized when the performance obligations to provide capacity to the relevant ISOs/RTOs or counterparties are fulfilled.

Amounts with counterparties in the table below represent minimum guaranteed capacity revenues as determined on a contract by contract basis and do not represent the full amount of capacity that is expected to be delivered.

2026 2027 2028 2029 2030 2031 and Thereafter

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Remaining performance obligations $ 1,768 $ 1,665 $ 733 $ 215 $ 215 $ 3,293 $ 7,889

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

Trade Accounts Receivable

2024 December 31,

(in millions)

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Allowance for credit losses on accounts receivable at end of period $ 89 $ 79 $ 61

GOVERNMENT ASSISTANCE

OTHER INCOME, NET

Year Ended December 31,

2025 2024 2023

(in millions)

NDT net income (a) $ 231 $ 170 $ —

Insurance settlements (b) 120 23 24

Gain on sale of land (c) — 6 95

Gain on TRA settlement (d) — 10 29

Interest income 18 65 86

All other 25 17 9

Total other income, net $ 394 $ 291 $ 243

(a) Includes interest, dividends, and net realized and unrealized gains (losses) associated with NDTs of the PJM nuclear facilities.

Reported in the East segment.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(b) For the year ended December 31, 2025, represents involuntary conversion gain for Martin Lake Incident insurance proceeds reported in the Texas Segment (see Note 8 for additional information).

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, 2023, $ 94 million reported in the Asset Closure segment and $ 1 million reported in the Texas segment.

(d) Reported in the Corporate and Other.

GOVERNMENT GRANTS

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 .

enacted the IRA, which introduced various energy tax credits.

Among these, it acknowledged the importance of existing carbon-free nuclear power by establishing a nuclear Production Tax Credit under section 45U (nuclear PTC), a solar PTC, new technology-neutral ITCs and PTCs that apply to various different clean energy technologies, and a new stand-alone battery storage investment tax credit.

The nuclear PTC provides a federal tax credit of up to $15 per MWh, subject to phase out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively.

The nuclear PTC applies to existing nuclear facilities from 2024 through 2032 subject to an annual inflation adjustment.

The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to ASC 832.

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.

In the years ended December 31, 2025 and 2024, we recognized transferable nuclear PTC revenues of $ 220 million and $ 545 million, respectively.

Nuclear PTC revenues are an estimate based on annual gross receipts generated from qualifying nuclear production in 2025 and 2024 and reflect our determination that we will meet the prevailing wage requirements necessary to earn the five times multiplier.

Our computation of gross receipts includes settled spot energy revenues and capacity revenues (applicable to our PJM nuclear units only) at each nuclear unit and excludes any hedges and ancillary service revenue.

Treasury regulations may further define the scope of the legislation in many important respects, including interpretive guidance on the definition of gross receipts for the nuclear PTC.

Any interpretive guidance on the definition of gross receipts that differs from the interpretation used in our estimate could result in a material change to PTC revenues recorded in 2025 and 2024 and would be reflected as a change in estimate in the period in which the guidance is received.

Transferable ITCs

In October 2025, our Oak Hill 200 MW solar facility in Texas met the requirements to be placed in service.

As a result, in the year ended December 31, 2025, we recognized $ 98 million of transferable ITCs associated with the project in other noncurrent assets in the consolidated balance sheet.

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, in the years ended December 31, 2025 and 2024, we recognized transferable ITCs of $( 2 ) million and $ 57 million, respectively, associated with Baldwin, and $( 1 ) million and $ 45 million, respectively, associated with Coffeen, in other noncurrent assets in the consolidated balance sheet.

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

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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

During 2025, we sold $ 490 million of transferable nuclear PTCs recognized from qualifying 2024 nuclear generation, of which $ 200 million was sold in January 2025, $ 90 million was sold in May and June 2025, and $ 200 million was sold in September 2025.

Cash proceeds of $ 469 million were received during the year ended December 31, 2025.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Vistra files a U.S.

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Income (loss) before income taxes $ 1,123 $ 3,467 $ 2,000

federal statutory rate 21 % 21 % 21 %

Income taxes at the U.S.

federal statutory rate 728 420 ( 328 )

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

federal statutory rate of 21% 236 21.0 % 728 21.0 % 420 21.0 %

State and local taxes, net of federal benefit (a) 26 2.3 % 68 2.0 % 71 3.6 %

Nontaxable or nondeductible items:

Nondeductible TRA accretion ( 1 ) ( 0.1 ) % 2 0.1 % 41 2.1 %

Transferable PTC revenues ( 115 ) ( 2 ) —

Equity awards ( 145 ) ( 12.9 ) % ( 53 ) ( 1.6 ) % ( 3 ) ( 0.2 ) %

Valuation allowance ( 2 ) ( 20 ) ( 8 )

Release of Uncertain Tax Positions — ( 35 ) —

Nondeductible 162(m) compensation 75 6.7 % 29 0.8 % 13 0.7 %

Transferable PTC revenues ( 46 ) ( 4.1 ) % ( 117 ) ( 3.4 ) % ( 2 ) ( 0.1 ) %

Other nontaxable or nondeductible items 7 0.6 % 2 0.1 % 2 0.1 %

Changes in valuation allowance — — % ( 3 ) ( 0.1 ) % — — %

Changes in unrecognized tax benefit — — % — — % ( 35 ) ( 1.8 ) %

( 3 ) ( 0.3 ) % — — % ( 1 ) ( 0.1 ) %

Other 30 2.7 % ( 1 ) — % 2 0.1 %

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

Effective tax rate 18.9 % 25.4 % 22.4 %

Total $ 179 15.9 % $ 655 18.9 % $ 508 25.4 %

(a) State and local taxes in Texas, Pennsylvania, and Illinois comprise the majority of this category.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes Paid (Net of Refunds)

Year Ended December 31,

2025 2024 2023

(in millions)

US Federal $ 11 $ 5 $ — (a)

US state and local

California 11 3 5

Illinois — (a)

Massachusetts — (a)

Ohio Municipalities 21 — (a)

Pennsylvania 28 6 5

Texas 19 17 — (a)

Total US state and local

$ 86 $ 50 $ 31

$ 97 $ 55 $ 31

(a) Income taxes paid did not meet the 5% disaggregation threshold for the periods presented.

Deferred Income Tax Balances

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Valuation allowance 73 75

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

Net Deferred Income Tax Liability $ ( 810 ) $ ( 688 )

As of December 31, 2025, we had total net deferred tax liabilities of approximately $ 810 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, 2025, 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.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2025, we had $ 3.8 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 $ 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, 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, 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.

The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax assets of zero and net deferred tax liabilities $ 4 million at December 31, 2025 and 2024, respectively.

OBBBA and CAMT

In July 2025, the legislation known as the OBBBA was signed into law and we have accounted for the effects in our consolidated financial statements.

Key changes include the immediate expensing of domestic research and development costs, the reinstatement of 100% bonus depreciation, and increases in the limitation of interest deductibility.

Certain provisions of the OBBBA will change the timing of cash tax payments in the current fiscal year and future year periods, however the legislation did not have a material impact on our effective income tax rate.

We do not expect Vistra to be subject to the corporate alternative minimum tax (CAMT) in the 2025 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess of $ 1 billion.

We have taken the CAMT and forecasted OBBBA impacts into account when forecasting cash taxes.

Liability for Uncertain Tax Positions

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federal, state and foreign jurisdictions and are, at times, subject to examinations by the IRS and other taxing authorities.

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

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

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

Uncertain tax positions totaled $ 4 million and $ 4 million as of December 31, 2025 and 2024, respectively.

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

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against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off.

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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.

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

The estimated remaining useful lives of our property, plant, and equipment ranges from 1 to 28 years.

Land is not depreciated.

Land and construction work in progress are 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)

Power generation and structures and office and other equipment $ 25,084 $ 22,943

Construction work in progress 1,917 1,060

Finance lease right-of-use assets 190 186

Nuclear fuel 2,036 1,843

Property, plant, and equipment — gross

29,864 26,635

Less accumulated depreciation ( 9,273 ) ( 8,020 )

Less finance lease right-of-use assets accumulated amortization

( 41 ) ( 33 )

Less accumulated amortization of nuclear fuel

( 704 ) ( 409 )

Property, plant, and equipment — net $ 19,846 $ 18,173

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

Depreciation and amortization of property, plant, and equipment (including the classification in the consolidated statements of operations) consisted of the following:

Property, Plant, and Equipment Consolidated Statements of Operations

Year Ended December 31,

2025 2024 2023

(in millions)

Power generation and structures and office and other equipment Depreciation and amortization $ 1,811 $ 1,662 $ 1,335

Finance lease right-of-use assets Depreciation and amortization 9 8 9

Nuclear fuel Fuel, purchased power costs, and delivery fees $ 487 $ 387 $ 91

Total property, plant, and equipment expense $ 2,307 $ 2,057 $ 1,435

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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)

Below are our operating facilities that have an announced retirement date.

Operating results for generation facilities with defined retirement dates are included in our Asset Closure segment in the calendar year following the year in which the retirement occurs.

The Moss Landing 300 MW and Moss Landing 100 MW battery facilities were transferred to the Asset Closure segment during the first quarter of 2025 and the fourth quarter of 2025, respectively, as we do not plan to return those assets to operations.

See Note 8 for additional information.

Facility Location ISO/RTO Fuel Type Net Capacity (MW)

Expected Retirement Date (a)

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

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

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.

Miami Fort North Bend, OH PJM Coal 1,020 By the middle of 2028

Newton Newton, IL MISO Coal 615 By the end of 2027 East

(a) Expected retirement dates my change if economic or other conditions dictate.

The Company intends to repower Coleto Creek and Miami Fort as gas-fueled facilities upon their retirements as coal-fueled facilities.

We are currently evaluating the feasibility of converting the other coal-fueled facilities with expected retirement dates in 2027 to gas-fueled facilities.

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.

In the year ended December 31, 2025, we recognized impairment losses of approximately $ 155 million related to the Moss Landing 100 MW battery (see Note 8 for additional information) and $ 73 million related to development projects we have no plans to complete.

In the year ended December 31, 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 .

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

LOSS EVENTS AND INSURANCE RECOVERIES

Moss Landing 300 Incident

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site (the Moss Landing Incident) that resulted in ceasing operations at all facilities at the Moss Landing complex until the fire was contained.

No injuries occurred due to the fire or the Company's response.

The Moss Landing complex includes two other battery facilities and a gas plant.

The gas plant returned to service in February 2025.

The Moss Landing 350 MW battery facility has a net book value of approximately $ 320 million as of December 31, 2025.

We are working towards a return to service in mid-2026, but we will continue to evaluate our restart plans following completion of our investigation into the cause of the fire.

After further consideration, management determined it would not return the Moss Landing 100 MW battery to service.

As a result of the damage caused by the Moss Landing Incident, during the three months ended March 31, 2025, we wrote-off the net book value of Moss Landing 300 of approximately $ 400 million to depreciation expense and moved the asset to the Asset Closure segment as we have no plans to return the Moss Landing 300 facility to operations (see Notes 7 and 21 for additional information).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As a result of the decision to not return the Moss Landing 100 MW battery to service, we performed an assessment of the recoverability of the facility's carrying value and, during the three months ended December 31, 2025, we recognized an impairment loss of approximately $ 155 million and moved the asset to the Asset Closure segment (see Notes 7 and 21 for additional information).

In July 2025, we entered into an Administrative Settlement Agreement and Order on Consent (ASAOC) with the EPA related to the Moss Landing 300 site.

Under the ASAOC, we are required to perform specific battery removal and remediation activities, including battery removal and disposal, building demolition, and air and water monitoring.

We estimate the total cost of these activities to be approximately $ 110 million.

We have incurred expenses of approximately $ 49 million on ASAOC activities through December 31, 2025.

As of December 31, 2025, our accrual for estimated future costs for the ASAOC activities is approximately $ 61 million, which is reflected in other current liabilities in the consolidated balance sheets.

This estimate assumes the ASAOC activities will be completed by the end of 2026.

Aside from battery removal and disposal, our estimate does not reflect costs associated with removal of other hazardous waste that could be identified as the demolition progresses as we are unable to estimate such costs until sampling of waste material is complete.

We will account for any adjustments to the accrual as a change in estimate in the period new information becomes available.

Additional impacts from the Moss Landing Incident include loss of revenue from the facilities being offline and may include litigation costs, other negotiated settlements of contracts with counterparties, and additional non-cash impairment losses.

See Note 18 for additional information.

We have filed insurance claims against applicable insurance policies with combined business interruption and property loss limits of $ 500 million, net of deductibles, of which approximately $ 500 million has been collected through February 2026.

The initial insurance receivable asset related to expenses we believe were probable of recovery from property damage insurance was $ 425 million, recorded as offsets to the expenses incurred in other noncurrent assets in the consolidated balance sheets.

See Insurance Recoveries for additional information.

While we expect future revenues in the West segment to decrease relative to 2024 revenues with the Moss Landing 300 and 100 MW battery facilities not returning to service, given the uncertainty in the timing of the restart of the Moss Landing 350 MW battery facility and additional expenses that could be incurred related to the Moss Landing Incident, we cannot predict the full impact this event will have on our 2026 financial statements.

Martin Lake Unit 1 Incident

On November 27, 2024, we experienced a fire at Unit 1 of our Martin Lake facility in ERCOT (the Martin Lake Incident), an 815 MW unit.

We wrote-off the unit's net book value of less than $ 1 million to depreciation expense in December 2024.

The unit returned to service in February 2026.

We estimate total cash capital expenditures required to restore the unit to service was approximately $ 384 million, of which approximately $ 271 million in cash capital expenditures have been incurred as of December 31, 2025.

We expect to recover a majority of the expenditures associated with the Martin Lake Incident through property damage insurance and to receive additional business interruption proceeds.

During the year ended December 31, 2025, we recognized property damage insurance recoveries of $ 160 million, of which $ 40 million was recorded as an offset to operating costs incurred to restore the unit to service, and $ 120 million was recorded as a gain in other income, net in the consolidated statements of operations.

During the year ended December 31, 2025, we recognized business interruption insurance proceeds of $ 47 million recorded in operating revenues.

See Insurance Recoveries for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Insurance Recoveries

The following table summarizes the expenses recorded, net of property damage insurance recoveries, related to the Moss Landing Incident and Martin Lake Incident during the year ended December 31, 2025.

Year Ended December 31, 2025

Moss Landing Incident Martin Lake Incident Total

(in millions)

Write-off of net book value of facility to depreciation and amortization $ 400 $ — $ 400

Operating costs incurred to restore Martin Lake to service — 40 40

Incurred and estimated cost of ASAOC activities to operating costs (a) 102 — 102

Total incident expense $ 502 $ 40 $ 542

Property damage insurance receivable as of the beginning of the period (b) $ — $ — $ —

Recovery of incident expense recorded to insurance receivable 425 40 465

Insurance recovery gain recorded in other income, net

Insurance proceeds received ( 227 ) ( 140 ) ( 367 )

Property damage insurance receivable as of the end of the period (b) $ 198 $ 20 $ 218

Total incident expense, net of property damage insurance recoveries $ 77 $ — $ 77

(a) Total estimated costs of ASAOC activities is expected to be approximately $ 110 million, of which $ 102 million was recorded in operating costs in the consolidated statements of operations.

Amounts above exclude $ 8 million of estimated demolition and battery removal costs reclassified from the Moss Landing 300 ARO to other current liabilities during the three months ended March 31, 2025.

(b) Property damage insurance receivable is included in other noncurrent assets on the consolidated balance sheets.

The following table summarizes the business interruption insurance recoveries related to the Moss Landing Incident and Martin Lake Incident during the year ended December 31, 2025.

Year Ended December 31, 2025

Moss Landing Incident Martin Lake Incident Total

(in millions)

Business interruption insurance proceeds realized (a)

$ 71 $ 47 $ 118

(a) Business interruption insurance proceeds are included in operating revenues in the consolidated statements of operations.

We expect to receive additional property damage and business interruption insurance proceeds related to the Martin Lake Incident and additional business interruption insurance proceeds related to the Moss Landing Incident which are not included in the property damage insurance receivable as of the year ended December 31, 2025.

These additional proceeds will be recorded as income in the period they are realized.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

As of December 31, 2025 and 2024, the carrying value of goodwill totaled $ 2.810 billion and $ 2.807 billion, respectively.

Retail Segment

Texas Segment

Retail Reporting Unit (a)

Texas Generation Reporting Unit

Retail Segment Texas Segment

Retail Reporting Unit (a) Texas Generation Reporting Unit Goodwill Pending Allocation

Total Goodwill

2 unchanged sentences

$ 2,461 $ 122 $ 224 $ 2,807

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

Measurement period adjustment recorded in connection with the Energy Harbor Merger (b)

227 — ( 224 ) 3

Balance at December 31, 2025

1 unchanged sentence

(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.

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, 2024.

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

(b) Includes the allocation of goodwill attributable to the Energy Harbor acquisition to the retail reporting unit (see Note 2 for additional information).

Identifiable Intangible Assets and Liabilities

7 unchanged sentences

(in millions)

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

Retail customer relationships $ 2,173 $ 2,067 $ 106 $ 2,173 $ 1,977 $ 196

Software and other technology-related assets 656 365 291 601 293 308

13 unchanged sentences

Total identifiable intangible liabilities $ 138 $ 155

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

2 unchanged sentences

(in millions)

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

Retail customer relationships Depreciation and amortization 1 $ 90 $ 111 $ 98

Software and other technology-related assets Depreciation and amortization 2 69 60 58

Retail and wholesale contracts Operating revenues/Fuel, purchased power costs, and delivery fees 3 ( 9 ) ( 12 ) 8

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

Other identifiable intangible assets (a) Fuel, purchased power costs, and delivery fees/Depreciation and amortization 4 488 414 357

Total intangible asset expense, net $ 638 $ 573 $ 521

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.

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

12 unchanged sentences

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, 2025.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Estimated Amortization of Identifiable Intangible Assets

3 unchanged sentences

COLLATERAL FINANCING AGREEMENT WITH AFFILIATE

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

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

The Trust is not consolidated by Vistra.

8 unchanged sentences

As of December 31, 2025 and 2024, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $ 444 million and $ 435 million, respectively, and is reported in the consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DEBT, CREDIT FACILITIES, AND FINANCINGS

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

Debt, credit facilities and financing obligations on the consolidated balance sheets consisted of the following:

(in millions)

2 unchanged sentences

Vistra Operations debt 15,627 15,405

15,405 14,517

Long-term debt before unamortized premiums, discounts, and issuance costs 17,196 16,469

16,469 14,517

Unamortized premiums, discounts, and issuance costs ( 153 ) ( 171 )

( 171 ) ( 115 )

Long-term debt including debt due currently

Long-term debt including amounts due currently

$ 17,043 $ 16,298

Short-term borrowings

Accounts receivable financing $ 1,225 $ 750

Forward repurchase obligation $ 632 $ 1,335

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt

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

The Company's long-term debt obligations, including amounts due currently, consisted of the following:

(in millions)

Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 $ 2,450 $ 2,475

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

BCOP Credit Facility, Bridge Loans 367 367

BCOP Credit Facility, Construction / Term Loans 505 —

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

1 unchanged sentence

5.125 % Senior Secured Notes, due May 13, 2025

3.550 % Senior Secured Notes, due July 15, 2024

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

4.300 % Senior Secured Notes, due October 15, 2028

4.300 % Senior Secured Notes, due July 15, 2029

4.600 % Senior Secured Notes, due October 15, 2030

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

5.250 % Senior Secured Notes, due October 15, 2035

Total Vistra Operations Senior Secured Notes 6,400 5,144

1 unchanged sentence

3.375 % Revenue Bond, due August 1, 2029

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

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

3.750 % Revenue Bond, due October 1, 2047

14 unchanged sentences

Total long-term debt less amounts due currently $ 15,842 $ 15,418

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt Maturities

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

Long-term debt maturities as of December 31, 2025 are as follows:

December 31, 2025

4 unchanged sentences

Credit Facilities

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

Our credit facilities and related available capacity as of December 31, 2025 are presented below.

December 31, 2025

Credit Facilities Maturity Date Facility

(Long-Term Debt, Including Amounts Due Currently)

Limit Borrowings Outstanding

Letters of Credit Outstanding Available

4 unchanged sentences

Total Vistra Operations Credit Facilities $ 5,890 $ 2,830 $ 1,064 $ 1,996

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

Vistra Operations Commodity-Linked Facility September 30, 2026 1,750 1,420 — 2

Total Vistra Operations debt $ 7,640 $ 4,250 $ 1,064 $ 1,998

Project-level debt:

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

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

Bridge Loans January 30, 2026 (a) / December 3, 2026

Construction / Term Loans (b)

BCOP Credit Facility 872 872 — —

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

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

Total project-level debt $ 1,569 $ 1,569 $ — $ —

Total credit facilities $ 9,209 $ 5,819 $ 1,064 $ 1,998

(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.

(a) In January 2026, Vistra repaid the $ 106 million Oak Hill Bridge Loan at maturity.

See additional information in BCOP Project-level Credit Facilities discussion below.

(b) Maturity dates between December 3, 2026 and December 3, 2029.

See additional information in BCOP Project-level Credit Facilities discussion below.

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

As of December 31, 2025, the Vistra Operations Credit Facilities have aggregate commitments of up to $ 5.890 billion in senior secured, first-lien revolving credit commitments and outstanding term loans (Vistra Operations Credit Facilities).

The Vistra Operations Credit Facilities consist of (i) revolving credit commitments (including aggregate revolving letter of credit commitments) of up to $ 3.440 billion (Revolving Credit Facility), and (ii) term loans of $ 2.450 billion (Term Loan B-3 Facility).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Borrowings under the Revolving Credit Facility bear interest based the forward-looking term rate based on SOFR (Term SOFR) plus a spread that ranges from 1.25 % to 2.00 %.

We pay fees on any undrawn amounts of the Revolving Credit Facility ranging from 17.5 basis points to 35.0 basis points.

Letters of credit issued under the Revolving Credit Facility are subject to a fee that ranges from 1.25 % to 2.00 % .

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

As of 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.

As of December 31, 2025, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 17.5 and 27.0 basis points, respectively, and the applicable fee for the letters of credit issued under the Revolving Credit Facility was 1.725 %.

Borrowings under the Revolving Credit Facility are included in short-term borrowings in the consolidated balance sheets.

Term Loan B-3 Facility — The Term Loan B-3 Facility is used for general corporate purposes.

Borrowings under the Term Loan B-3 Facility bear interest based on the applicable Term SOFR, plus a fixed spread of 1.75 %.

The weighted average interest rate, before taking into consideration interest rate swaps (see Note 13 for additional information) on outstanding borrowings of $ 2.450 billion, was 5.466 % as of December 31, 2025.

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

Amounts paid cannot be reborrowed.

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

The Vistra Operations Credit Agreement includes certain collateral suspension provisions that would take effect upon Vistra Operations achieving unsecured investment grade ratings from two ratings agencies and there being no Term Loans (under and as defined in the Vistra Operations Credit Agreement) then outstanding (or the holders thereof agreeing to release such security interests).

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

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

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

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

Other Information — Obligations under the Vistra Operations Credit Facilities are secured by liens on 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 Agreement.

The Vistra Operations Credit Agreement includes collateral suspension provisions that become effective if Vistra Operations achieves unsecured investment-grade credit ratings from at least two ratings agencies and no term loans (as defined in the Vistra Operations Credit Agreement) remain outstanding (or the holders thereof agree to release their security interests).

The collateral suspension provisions will remain in effect unless and until Vistra Operations ceases to maintain unsecured investment-grade ratings from at least two ratings agencies, at which time collateral reversion provisions would apply, 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, provided such agreements satisfy the applicable criteria set forth therein.

The Vistra Operations Credit Facilities contain customary affirmative and negative covenants applicable to Vistra Operations and its restricted subsidiaries, including affirmative covenants requiring the delivery of financial and other information to the administrative agent and restrictions on changes to lines of business.

The negative covenants restrict 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 Agreement.

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

2 unchanged sentences

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.

As of December 31, 2025, Vistra Operations can distribute approximately $ 11.2 billion to Parent without the consent of any party.

The amount available for distribution has been reduced by distributions made by Vistra Operations to Parent of approximately $ 1.625 billion, $ 1.705 billion, and $ 1.625 billion during the years ended December 31, 2025, 2024 and 2023, 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, 2025, all of the restricted net assets of Vistra Operations may be distributed to Parent.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Vistra Operations Commodity-Linked Revolving Credit Facility

1 unchanged sentence

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

In October 2025, Vistra Operations amended the Commodity-Linked Facility to, among other things, extend the maturity date to September 30, 2026.

As of December 31, 2025, the borrowing base of $ 1.422 billion is lower than the facility limit which represents the aggregate commitments of $ 1.75 billion.

Borrowings under the Commodity-Linked Facility are included in short-term borrowings in the consolidated balance sheets.

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.

1 unchanged sentence

Vistra Operations intends to use any borrowings provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time to time and for other working capital and general corporate purposes.

Interest on the Commodity-Linked Facility bears interest (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.

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

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

1 unchanged sentence

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

As of December 31, 2025, the weighted average interest rate on outstanding borrowings under the Commodity-Linked Facility was 5.45 %.

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.

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

The BCOP Credit Agreement provides for (i) bridge loan commitments of $ 367 million for the Oak Hill and Pulaski projects (the Bridge Loans) and (ii) construction and term loan commitments of $ 528 million (the Construction/Term Loan Facility), together with debt service reserve letter of credit commitments of $ 29 million (the Debt Service Reserve and, collectively with the Bridge Loans and the Construction/Term Loan Facility, the BCOP Credit Facility).

As of December 31, 2025, outstanding Bridge Loans totaled $ 106 million for Oak Hill and $ 261 million for Pulaski, with scheduled maturities in November 2025 and December 2026, respectively, subject to the terms of the BCOP Credit Agreement.

In October 2025, the maturity date of the $ 106 million Oak Hill Bridge Loans was extended to January 30, 2026.

Interest on the Bridge Loans is payable in arrears at the applicable Term SOFR rate elected in the related borrowing notice plus a fixed margin of 1.625 % per annum, and the weighted-average interest rate on outstanding Bridge Loan borrowings was 5.355 % as of December 31, 2025.

Repayment of the Bridge Loans is guaranteed by Vistra as the beneficiary of the underlying investment tax credits expected to be generated by the applicable projects.

In January 2026, Vistra repaid the $ 106 million Oak Hill Bridge Loan at maturity.

The Construction/Term Loan Facility consists of (i) term loans supporting the Baldwin and Coffeen projects and (ii) construction loans used to fund the Oak Hill and Pulaski projects during their construction periods, which convert to term loans upon each project's achievement of commercial operation and satisfaction of the applicable term conversion conditions.

Construction and term loan activity during 2025 included the following:

• Baldwin and Coffeen :

In April 2025, BCOP funded $ 75 million and $ 45 million of term loans for the Baldwin and Coffeen projects, respectively, each of which will mature in December 2029.

In addition, BCOP issued $ 7 million of letters of credit under the Debt Service Reserve facility to support these term loans.

In May 2025, BCOP funded $ 88 million of construction loans for the Oak Hill project with a scheduled maturity in November 2025.

In October 2025, the Oak Hill project achieved commercial operation, and the construction loans automatically converted into a term loan maturing in December 2029.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In July, August, and December 2025, BCOP funded an aggregate of $ 297 million of construction loans for the Pulaski project.

These construction loans mature in December 2026 and, subject to satisfaction of certain conditions, will convert into a term loan maturing in December 2029.

Interest on construction and term loans under the Construction/Term Loan Facility is payable in arrears at the applicable Term SOFR rate elected in the borrowing notice plus a fixed margin of 1.875 % per annum for construction loans and 2.000 % per annum for term loans.

The weighted-average interest rate on outstanding construction and term loan borrowings was 5.821 % as of December 31, 2025.

Beginning on the applicable term funding or term conversion date, the term loans amortize over a 20-year period, with principal and interest payments funded from the cash flows generated by the underlying projects.

Fees on issued debt service reserve letters of credit accrue at 2.000 % per annum and are payable in arrears.

Commitment fees on undrawn loan commitments and unissued letter of credit commitments are payable quarterly in arrears at a fixed percentage of the applicable loan margin.

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

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.

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

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

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

Vistra Zero 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.

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

Interest on the Term Loan B Facility is based on Term SOFR plus 2.00 % per annum.

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

The weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings of $ 697 million was 5.716 % as of December 31, 2025.

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

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

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).

Between August 2020 and December 2025, we entered into uncommitted standby letter of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities).

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

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

The Secured LOC Facilities do not have stated expiration dates and are used for general corporate purposes.

As of December 31, 2025, $ 1.332 billion of letters of credit were outstanding under the Secured LOC Facilities.

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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.

In October 2025, the Alternative LOC Facilities were amended to increase the commitment cap from $ 500 million to a total of $ 800 million.

As of December 31, 2025, the total capacity was $ 760 million and $ 608 million of letters of credit were outstanding under the Alternative LOC Facilities.

1 unchanged sentence

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Covenants

The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and revolving letters of credit outstanding (excluding all undrawn revolving letters of credit and cash collateralized backstopped revolving letters of credit) exceed 35 % of the revolving commitments), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00).

In addition, 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, 2025, we were in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants.

Vistra Operations Senior Secured Notes

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The Senior Secured Notes are secured by a first-priority security interest in the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities and contains certain covenants and restrictions consistent with the Vistra Operations Credit Facilities.

In 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).

In January 2026, Vistra Operations issued $ 2.25 billion aggregate principal amount of senior secured notes, consisting of $ 1.0 billion aggregate principal amount of 4.700 % senior secured notes due 2031 ( 4.700 % Senior Secured Notes) and $ 1.250 billion aggregate principal amount of 5.350 % senior secured notes due 2036 ( 5.350 % 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 January 31 and July 31 beginning July 31, 2026.

Net proceeds totaling approximately $ 2.230 billion, together with cash on hand, will be used to (i) fund a portion of the consideration for the Cogentrix Transaction (see Note 2 for additional information), (ii) for general corporate purposes, including to repay existing indebtedness, and (iii) to pay fees and expenses related to the offering.

In October 2025, Vistra Operations issued $ 2.0 billion aggregate principal amount of senior secured notes, consisting of $ 750 million aggregate principal amount of 4.300 % senior secured notes due 2028 ( 4.300 % Senior Secured Notes), $ 500 million aggregate principal amount of 4.600 % senior secured notes due 2030 ( 4.600 % Senior Secured Notes) and $ 750 million aggregate principal amount of 5.250 % senior secured notes due 2035 ( 5.250 % Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act.

Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning April 15, 2026.

Net proceeds totaling approximately $ 1.984 billion, together with cash on hand, will be used for (i) to support refinancing activities for outstanding indebtedness (see Vistra Operations Senior Unsecured Notes below), (ii) for general corporate purposes, including to fund a portion of the Lotus Acquisition (see Note 2 for additional information), and (iii) to pay fees and expenses related to the offering.

In May 2025, the $ 744 million outstanding principal amount of the 5.125 % Senior Secured Notes due May 2025 was repaid at maturity.

Energy Harbor Revenue Bonds

4 unchanged sentences

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Vistra Operations Senior Unsecured Notes

2 unchanged sentences

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

In 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).

In October 2025, Vistra Operations used a portion of the proceeds from the October 2025 issuance of Vistra Operations Senior Secured Notes discussed above to redeem the $ 1.0 billion outstanding principal amount of 5.500 % Senior Unsecured Notes due 2026.

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.

As part of the Lotus Acquisition in October 2025, Vistra assumed a senior secured credit facility with an existing $ 803 million term loan due August 1, 2030.

In November 2025, we repaid the term loan for $ 808 million including accrued interest and fees.

Accounts Receivable Financing

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

In 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.

In June 2025, the Receivables Facility was amended to add Dynegy Energy Services Mid-Atlantic, LLC.

In July 2025, the Receivables Facility was amended to increase the purchase limit from $ 1.0 billion to $ 1.1 billion and to extend the term of the Receivables Facility to July 2026.

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

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

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

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

Amounts funded by the Purchasers to RecCo are reflected as accounts receivables financing 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.

2 unchanged sentences

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.

As of December 31, 2025, outstanding borrowings under the Receivables Facility totaled $ 1.1 billion and were supported by $ 1.538 billion of RecCo gross receivables.

As of December 31, 2024, there were $ 750 million in outstanding borrowings under the Receivables Facility.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Repurchase Facility

1 unchanged sentence

In July 2025, the Repurchase Facility was renewed until July 2026 while maintaining the facility size of $ 125 million.

The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and 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.

The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and represents a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility.

Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Repo Transaction).

2 unchanged sentences

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.

As of December 31, 2025, outstanding borrowings under the Repurchase Facility totaled $ 125 million.

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

Forward Repurchase Obligation

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

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

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

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

Payments remaining due to Nuveen are as follows:

In June 2025 and December 2025, Vistra made scheduled installment payments to reduce the forward repurchase obligation by $ 781 million, including $ 703 million of principal and $ 78 million of interest.

Principal and interest payments remaining due to Nuveen are as follows:

December 31, 2025

1 unchanged sentence

Total scheduled payments under the UPAs $ 669

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.

The present value of the remaining payment obligations to Nuveen discounted at 6 % was $ 632 million at December 31, 2025 and is included in forward repurchase obligation due currently on the consolidated balance sheet.

The amount discounted at 6 % was $ 1.335 billion at December 31, 2024, and is included in forward repurchase obligation due currently and forward repurchase obligation, less amounts due currently in the consolidated balance sheets.

Interest Expense and Related Charges

5 unchanged sentences

Amortization of debt issuance costs, discounts, and premiums 46 34 26

Facility Fee expense 15 8 —

Debt extinguishment gain — ( 6 ) ( 3 )

2 unchanged sentences

Total interest expense and related charges $ 1,179 $ 900 $ 740

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 13, was 5.18 %, 5.23 %, and 5.69 % as of December 31, 2025, 2024 and 2023, respectively.

32 unchanged sentences

Total lease liabilities $ 327 $ 338

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Cash Flow Information

24 unchanged sentences

2028 10 15 25

2028 10 13 23

Thereafter 191 327 518

1 unchanged sentence

Imputed interest ( 145 ) ( 176 ) ( 321 )

( 175 ) ( 176 ) ( 351 )

Present value of lease liabilities $ 105 $ 222 $ 327

1 unchanged sentence

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Commodity Derivatives

10 unchanged sentences

As of December 31, 2025, Vistra has entered into the following interest rate swaps:

Notional Amount Expiration Date Rate Range (c)

Notional Amount Expiration Date Rate Range (d)

(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 %

Swapped to fixed (a) $ 3,000 July 2026 2.89 % - 2.97 %

Swapped to variable (a) $ 700 July 2026 1.44 % - 1.49 %

Swapped to fixed (b) $ 2,300 December 2030 3.20 % - 3.76 %

Swapped to fixed (c)

$ 416 March, July and October 2045

3.95 % - 4.09 %

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

2 unchanged sentences

(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

These swaps will hedge our exposure on $ 2.3 billion of floating rate debt from August 2026 through December 2030.

(c) In March 2025, May 2025, and July 2025, BCOP entered into interest rate swaps with notional amounts of approximately $ 108 million, $ 70 million, and $ 238 million, respectively.

These swaps are effective as of April 2025, October 2025, and October 2026, and will expire in March 2045, October 2045 and July 2045, respectively.

These swaps are intended to hedge BCOP's exposure on approximately $ 416 million of floating rate Construction/Term Loan Facility commitments issued under the BCOP Credit Agreement.

(see Note 11 for additional information).

(d) The rate ranges reflect the fixed leg of each swap at the applicable Term SOFR rate.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Effect of Derivative Instruments on 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.

1 unchanged sentence

December 31, 2025

Derivative Contract Assets

Derivative Contract Liabilities

Derivative Contract Assets Derivative Contract Liabilities

Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total

6 unchanged sentences

Offsetting instruments (a) $ ( 2,622 ) $ ( 10 ) $ 2,622 $ 10 —

$ ( 2,532 ) $ ( 28 ) $ 2,532 $ 28 —

Financial collateral (received) pledged (b) $ ( 7 ) $ — $ 891 $ — 884

1 unchanged sentence

December 31, 2024

Derivative Contract Assets

Derivative Contract Liabilities

Derivative Contract Assets Derivative Contract Liabilities

Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total

6 unchanged sentences

Offsetting instruments (a) $ ( 2,532 ) $ ( 28 ) $ 2,532 $ 28 —

$ ( 3,519 ) $ ( 28 ) $ 3,519 $ 28 —

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

$ ( 26 ) $ — $ 970 $ — 944

$ 599 $ 36 $ ( 2,395 ) $ ( 20 ) $ ( 1,780 )

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

(a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.

(b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Effect of Derivative Instruments in the Consolidated Statements of Operations

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Commodity contracts unrealized (gain) loss in operating revenues (a) $ 1,045 $ 1,140 $ 1,472

Commodity contracts unrealized (gain) loss in fuel and purchased power expense (a) 73 171 ( 722 )

Commodity contracts unrealized (gain) loss in fuel, purchased power costs, and delivery fees (a) ( 75 ) 73 171

Interest rate swaps unrealized (gain) loss in interest expense and related charges ( 15 ) ( 41 ) ( 78 )

Total reversals of previously recognized unrealized (gain) loss on derivative instruments $ 955 $ 1,172 $ 1,565

Unrealized net gains (losses) from changes in fair value on derivative instruments:

Unrealized net gain (loss) from changes in fair value on derivative instruments:

Commodity contracts unrealized gain (loss) in operating revenues $ ( 1,811 ) $ ( 127 ) $ ( 758 )

Commodity contracts unrealized gain (loss) in fuel and purchased power expense 69 ( 395 ) 375

Commodity contracts unrealized gain (loss) in fuel, purchased power costs, and delivery fees 33 69 ( 395 )

Interest rate swaps unrealized gain (loss) in interest expense and related charges ( 52 ) 94 42

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.

Total unrealized net gain (loss) from change in fair value on derivative instruments $ ( 1,830 ) $ 36 $ ( 1,111 )

Net unrealized gain (loss) on derivative instruments $ ( 875 ) $ 1,208 $ 454

(a) Excludes the realized effects of changes in fair value in the month the position settled, amounts related to positions entered into and settled in the same month, and physical retail and wholesale contracts accounted for as derivatives that did not financially settle but were realized at the contract's notional and price.

The realized effects of these items are included in operating revenues and fuel, purchased power costs, and delivery fees.

Derivative Volumes

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Interest rate swaps - fixed/variable $ 700 $ 700 Million U.S.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Credit Risk-Related Contingent Features of Derivatives

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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 have concentrations of credit risk with the counterparties to our derivative contracts that increase the risk that a default by any of our counterparties could have a material effect on our financial condition, results of operations and liquidity.

We maintain credit risk policies with regard to our counterparties to minimize overall credit risk.

These policies authorize specific risk mitigation procedures including, but not limited to, (i) requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our counterparties that allow for netting of positive and negative exposures, and (iii) 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.

These policies authorize specific risk mitigation procedures including, but not limited to, (i) requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our counterparties that allow for netting of positive and negative exposures, and (iii) credit enhancements (such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits) that are required in the event of a material downgrade in their credit rating.

December 31, 2025

(in millions, except percentages)

Credit risk exposure to derivative contract counterparties:

Gross exposure $ 3,777

Net exposure (a) $ 807

Largest net exposure from any single counterparty (a) $ 331

Percent of credit risk exposure to derivative contract counterparties related to banking and financial sector:

Gross exposure 72 %

Net exposure (a) 10 %

(a) Exposure after taking into effect netting arrangements, setoff provisions, and collateral.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FAIR VALUE MEASUREMENTS

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December 31, 2025 December 31, 2024

3 (a) Reclass (a)

Reclass (a) Total Level

Reclass (a) Total

(in millions)

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NDTs – equity securities (c)(d)(f) 806 821

NDTs – debt securities (c)(e)(f) 329 —

NDTs - other investments (c)(f) 28 —

Total assets $ 8,210 $ 7,767

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(b) See Note 13 for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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.

These investments include equity, debt and other 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, 2025.

(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.

(d) The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 and Russell 3000 Indices for U.S.

equity investments and the MSCI EAFE and MSCI All Country World ex-US Indices for non-U.S.

equity investments.

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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.

The debt securities had an average coupon rate of 4.02 % and 3.99 % as of December 31, 2025 and 2024, respectively, and an average maturity of eight years and seven years as of December 31, 2025 and 2024, respectively.

NDT debt securities held as of December 31, 2025 mature as follows:

$ 1.045 billion in one to five years, $ 599 million in five to 10 years and $ 415 million after 10 years.

$ 848 million in one to five years, $ 1.114 billion in five to 10 years and $ 455 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:

The following tables present the fair value of Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of December 31, 2025 and 2024:

December 31, 2025

Contract Type (a) Assets Liabilities Total, Net

Valuation Technique Significant Unobservable Input Range (b) Average (b)

Contract Type (a) Assets Liabilities Total, Net Valuation Technique Significant Unobservable Input Range (b) Average (b)

(in millions)

Electricity purchases and sales $ 269 $ ( 1,607 ) $ ( 1,338 ) 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

Illiquid delivery periods for hub power prices (d) $ 25 to $ 135 $ 80

Market Heat Rates (d) $ 25 to $ 130 $ 78

Options — ( 177 ) ( 177 ) Option Pricing Model Natural gas to power correlation (e) 15 % to 100 % 58 %

Power and natural gas volatility (e) 5 % to 1,120 % 563 %

Financial transmission rights/Congestion revenue rights

190 ( 25 ) 165 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 35 ) to $ 20 $ ( 8 )

Financial transmission rights/Congestion revenue rights 277 ( 34 ) 243 Market Approach (f) Illiquid price differences between settlement points (g) $ ( 12 ) to $ 25 $ 7

Natural gas 16 ( 24 ) ( 8 ) Income Approach Natural gas basis (h) $ ( 2 ) to $ 14 $ 6

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Total $ 573 $ ( 1,842 ) $ ( 1,269 )

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2024

Contract Type (a) Assets Liabilities Total, Net

Valuation Technique Significant Unobservable Input Range (b) Average (b)

Contract Type (a) Assets Liabilities Total, Net Valuation Technique Significant Unobservable Input Range (b) Average (b)

(in millions)

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Illiquid delivery periods for hub power prices and Heat Rates (d) $ 25 to $ 140 $ 83

Market Heat Rates (d)

$ 30 $ 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

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

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 $ 4

Illiquid delivery periods (i) $ — to $ 5 $ 2

Other (j) 10 — 10

Total $ 841 $ ( 1,593 ) $ ( 752 )

(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.

(a) (i) Electricity purchase and sales contracts include power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO, and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO, and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts.

(b) The range of the inputs may be influenced by factors such as time of day, delivery period, season, and location.

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(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:

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presents the changes in fair value of Level 3 assets and liabilities:

Year Ended December 31,

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Transfers out of Level 3 (b) 308 118 660

Net liabilities assumed in connection with the Energy Harbor Merger ( 13 ) — —

Net liabilities assumed in connection with acquisitions ( 410 ) ( 13 ) —

Net change ( 517 ) 292 175

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All Level 3 transfers during the periods presented are in and out of Level 2.

For the year ended December 31, 2025, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power derivatives where forward pricing inputs have become observable.

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

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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.

The Energy Harbor Merger and the Lotus Acquisition were 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.

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December 31, 2025 December 31, 2024

Fair Value Hierarchy Carrying Amount Fair

Instrument Fair Value Hierarchy Carrying Amount Fair

Value Carrying Amount Fair

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Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,417 $ 2,459 $ 2,435 $ 2,478

BCOP Credit Facilities Tax Credit Bridge Loan Level 3

BCOP Credit Facility Level 3 859 872 344 367

Vistra Zero Term Loan B Facility Level 2 687 688 685 697

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Equipment Financing Agreements Level 3 45 45 54 53

Forward Repurchase Obligation

1,335 1,335 — —

Forward Repurchase Obligation Level 3 632 632 1,335 1,335

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We determine fair value in accordance with accounting standards.

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Adjustment for change in estimates (b) — 90 90

Adjustment for obligations assumed through acquisition

1,368 — 1,368

Payments — ( 88 ) ( 88 )

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$ 3,374 $ 661 $ 4,035

(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.

(a) For the years ended December 31, 2025 and 2024, nuclear plant decommissioning accretion includes $ 94 million and $ 74 million, respectively, of accretion expense recognized in operating costs in the consolidated statements of operations and $ 60 million and $ 56 million, respectively, reflected as a change in regulatory liability in the consolidated balance sheets.

(b) There is a corresponding non-cash change in property, plant, and equipment related to land, reclamation, coal ash, and other ARO adjustments of $ 66 million and $ 52 million for the years ended December 31, 2025 and 2024, respectively.

For the next five years, Vistra is projected to spend approximately $ 561 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).

AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and the Beaver Valley, Perry, and Davis-Besse plants in PJM (the PJM nuclear facilities).

To estimate our nuclear decommissioning obligations we use a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates.

As of 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2025 and 2024, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $ 1.838 billion and $ 1.797 billion, respectively, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $ 2.589 billion and $ 2.249 billion, respectively.

As of December 31, 2025 and 2024, the difference between the carrying value of the ARO and the NDT represents a regulatory liability of $ 751 million and $ 452 million, respectively, 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.

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Total benefit costs recognized as expense $ 10 $ 14 $ 14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Market-Related Value of Assets Held in Pension Benefit Trusts

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Participant contributions — — 3 3

Plan amendments — 1 — —

Actuarial (gain) loss 13 ( 24 ) 3 ( 7 )

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Funded status at end of year $ ( 101 ) $ ( 124 ) $ ( 88 ) $ ( 89 )

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Retirement Plan OPEB Plans

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Amounts Recognized in Accumulated Other Comprehensive Income Consist of:

Net actuarial (gain) loss $ ( 5 ) $ 4 $ ( 22 ) $ ( 15 )

Net actuarial gain $ ( 4 ) $ ( 5 ) $ ( 19 ) $ ( 22 )

Prior services cost — — 1 1

Net actuarial (gain) loss and prior service cost $ ( 5 ) $ 7 $ ( 21 ) $ ( 14 )

Net actuarial gain and prior service cost $ ( 4 ) $ ( 5 ) $ ( 18 ) $ ( 21 )

Fair Value Measurement of Pension and OPEB Plan Assets

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As of December 31, 2025 and 2024, the Vistra OPEB plan assets measured at fair value totaled $ 10 million and $ 10 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.

At December 31, 2025 and 2024, assets consisted of $ 6 million and $ 7 million, respectively, of commingled funds valued at net asset value and $ 4 million and $ 3 million, respectively, of municipal bond, short- and medium-duration bond, and cash equivalent mutual funds classified as Level 1.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO) in Excess of Plan Assets

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Hedge funds 2 % - 6 % 4 % - 8 % 1 % - 2 %

Infrastructure funds 2 % - 6 % 4 % - 8 %

Retirement Plan Expected Long-Term Rate of Return on Assets Assumption

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Hedge funds 6.9 % 6.9 % 6.9 %

Infrastructure funds 8.0 % 8.0 %

Weighted average 6.1 % 6.0 % 5.8 %

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Benefit Plan Assumed Health Care Cost Trend Rates

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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.

Contributions to the Retirement Plan for the years ended December 31, 2025, 2024 and 2023 totaled $ 29 million, $ 19 million, and zero , respectively, and contributions in 2026 are expected to total $ 13 million.

OPEB plan funding for each of the years ended December 31, 2025, 2024 and 2023 totaled $ 8 million, $ 8 million, and $ 9 million, respectively, and funding in 2026 is expected to total $ 8 million.

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OPEB $ 9 $ 9 $ 8 $ 8 $ 8 $ 36

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Qualified Savings Plans

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Aggregate employer contributions to the qualified savings plans totaled $ 45 million, $ 46 million, and $ 33 million for the years ended December 31, 2025, 2024 and 2023, respectively.

STOCK-BASED COMPENSATION

Vistra 2016 Omnibus Incentive Plan

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 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:

(a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards, and (c) establish the terms and conditions of awards, including the price (if any) to be paid for the shares of the award.

The types of awards that may be granted under the 2016 Incentive Plan include stock options, RSUs, restricted stock, performance awards, and other forms of awards granted or denominated in shares of Vistra common stock, as well as certain cash-based awards.

If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised award shall again be available for awards under the 2016 Incentive Plan.

If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan.

Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation.

No awards under the 2016 Incentive Plan have been settled in cash since the Effective Date.

As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra stockholders.

Stock-Based Compensation Expense

Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows:

Year Ended December 31,

2025 2024 2023

(in millions)

Total stock-based compensation expense $ 113 $ 100 $ 77

Income tax benefit ( 25 ) ( 23 ) ( 18 )

Stock based-compensation expense, net of tax $ 88 $ 77 $ 59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock Options

Stock options outstanding at December 31, 2025 are all held by current or former employees.

The following table summarizes our stock option activity:

Year Ended December 31, 2025

Stock Options

(in thousands) Weighted

Average Exercise Price Weighted Average Remaining Contractual Term (Years) Aggregate Intrinsic Value (in millions)

Total outstanding at beginning of period 3,600 $ 19.97 3.5 $ 424.4

Exercised ( 2,216 ) $ 18.89

Forfeited or expired ( 6 ) $ 22.97

Total outstanding at end of period 1,378 $ 21.69 3.0 $ 192.4

Exercisable at December 31, 2025 1,378 $ 21.69 3.0 $ 192.4

As of December 31, 2025, 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 years ended December 31, 2025, 2024 and 2023.

Restricted Stock Units

The following table summarizes our restricted stock unit activity:

Year Ended December 31, 2025

Restricted Stock Units

(in thousands) Weighted

Average Grant Date Fair Value

Total nonvested at beginning of period 3,054 $ 34.30

Granted 518 $ 127.91

Vested ( 1,624 ) $ 30.69

Forfeited ( 124 ) $ 53.61

Total nonvested at end of period 1,824 $ 62.71

As of December 31, 2025, $ 54 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 1.6 years.

Performance Stock Units

We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis.

All PSUs have a three year performance period and a payout opportunity of 0 - 200 % of target ( 100 %), which is intended to be settled in shares of Vistra common stock.

We recognized compensation expense associated with PSUs of $ 46 million, $ 54 million, and $ 36 million for the years ended December 31, 2025, 2024 and 2023, respectively.

As of December 31, 2025, we have $ 54 million of unrecognized compensation cost associated with PSUs.

Employee Stock Purchase Plan (ESPP)

The Company offers participation in the ESPP which allows eligible employees to elect to withhold between 1 % and 10 % of their eligible compensation to purchase shares of Vistra common stock at the lesser of 85 % of its market value on the offering date or 85 % of the fair market value on the exercise date.

An offering date occurs each January 1 and July 1 and an exercise date occurs each June 30 and December 31 beginning in 2026.

The ESPP allows for the issuance of 1,000,000 shares of our common stock, all of which were available for purchase pursuant to the ESPP as of December 31, 2025.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

COMMITMENTS AND CONTINGENCIES

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Expenditures under our coal purchase and coal transportation agreements totaled $ 733 million, $ 744 million, and $ 936 million for the years ended December 31, 2025, 2024 and 2023, respectively.

We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions.

Letters of Credit

As of December 31, 2024, we had outstanding letters of credit totaling $ 2.935 billion as follows:

• $ 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;

Letters of Credit, Surety Bonds, and Collateral Support Obligation

Letters of Credit — As of December 31, 2025, we had outstanding letters of credit totaling $ 3.004 billion as follows:

• $ 2.489 billion to support commodity risk management and collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and $ 679 million of collateral postings with ISOs/RTOs;

• $ 279 million to support battery and solar development projects;

• $ 25 million to support executory contracts and insurance agreements;

• $ 110 million to support ASAOC requirements with the EPA (see Note 8 for additional information);

• $ 86 million to support our REP financial requirements with the PUCT;

• $ 25 million to support executory contracts and insurance agreements;

• $ 15 million for other credit support requirements.

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.

Surety Bonds — Surety bonds provide financial performance assurance to third parties on behalf of certain Company subsidiaries for obligations under various contracts and legal obligations in the normal course of business.

In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety.

Our liability with respect to any particular surety bond is released once the obligations secured by the surety bond are performed.

As of December 31, 2025, we had outstanding surety bonds totaling $ 987 million, including $ 81 million with ISOs/RTOs.

Collateral Support Obligation — The RCT has rules in place to assure that parties can meet their mining reclamation obligations.

In September 2016, the RCT agreed to a collateral bond of up to $ 975 million to support Luminant's reclamation obligations.

The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $ 975 million) before the other first-lien lenders in the event of a liquidation of our assets.

Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Litigation and Regulatory Proceedings

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Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material.

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

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

In April 2023, the U.S.

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

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

The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers.

The vast majority of the conduct in question occurred prior to our acquisition of IG&E.

In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 5 -year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint.

In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the five -year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint.

Ohio House Bill 6 ("HB6") — In July 2019, Ohio adopted a law referred to as HB6, which, among other things, provided subsidies for two nuclear power plants which we acquired in March 2024 upon the closing of our merger with Energy Harbor.

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Motions to dismiss those cases remain pending and the case is currently stayed.

Dorrell Antitrust Litigation — In July 2025, an antitrust lawsuit was filed in the U.S.

District Court for the District of Maryland against Human Resources Consultants, LLC, Accelerant Technologies, Constellation Energy Corporation and 25 other companies, including Vistra Corp.

and Luminant Generation Company, LLC.

Plaintiffs allege that since at least May 2003, the defendants exchanged confidential compensation information and conspired to fix and suppress compensation of all persons employed in nuclear power generation in violation of federal antitrust law.

In October 2025, motions to dismiss these claims were filed and the Plaintiffs amended their lawsuit.

In December 2025, motions to dismiss these amended claims were filed.

We believe we have strong defenses to this lawsuit and intend to defend against this case vigorously.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Winter Storm Uri Legal Proceedings

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We responded to all those investigatory requests.

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

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

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

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

In addition, in January 2022, an insurance subrogation lawsuit was filed in Austin state court by over one hundred insurance companies against ERCOT, Vistra and several other defendants.

The lawsuit seeks recovery of insurance funds paid out by these insurance companies to various policyholders for claims related to Winter Storm Uri, and that case has also now been consolidated with the MDL proceedings.

In the summer of 2022, various defendant groups filed motions to dismiss five so-called bellwether cases, and the MDL court heard oral argument on those motions in October 2022.

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

These cases were transferred to a single multi-district litigation (MDL) pretrial judge for all pretrial proceedings.

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

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

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

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

The plaintiffs have petitioned the Texas Supreme Court to review that decision.

The plaintiffs have petitioned the Texas Supreme Court to review that decision and filed their opening brief in September 2025.

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

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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.

Several lawsuits have been filed in California federal and state courts against Vistra, LG Energy Solution (LG), and others, as a result of this incident.

The EPA is providing control and oversight of clean up and remediation efforts on the site.

In July 2025, we entered into an ASAOC with the EPA that requires us to perform certain activities, which primarily include battery removal and disposal, building demolition, and air and water monitoring at the Moss Landing 300 site.

By entering into this ASAOC, we will conduct these activities under the EPA's oversight.

See Note 8 for additional information including costs incurred through December 31, 2025 and estimated future costs to be incurred related to these activities.

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.

In January 2025, President Trump issued a series of executive orders, including an order titled Unleashing American Energy (the Order) that ordered that all federal agencies are to review all existing regulations, orders, and other actions for consistency with the administration's policy goals, and develop an action plan within 30 days to resolve any policy inconsistencies.

The Order requires the EPA to review the GHG, CSAPR, Legacy CCR, and ELG rules discussed below.

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Attorney General may request a stay of the litigation involving these rules while the EPA conducts its reviews.

In addition to that Order, in April 2025, President Trump issued a series of additional executive orders on energy and deregulation priorities for his administration.

We will monitor implementation and any agency actions related to those and other executive orders.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Greenhouse Gas Emissions (GHG)

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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.

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.

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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.

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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.

Circuit Court has granted the EPA's motion for an abeyance of the case and status reports are due at 90 -day intervals.

In June 2025, the EPA published a proposed repeal of GHG emission standards for fossil fuel-fired electric generation units, which could moot this case if the proposal is finalized and would result in no further federal regulation of GHGs at electric generating units.

Additionally, in February 2026, the EPA issued a rule that repeals the agency's prior 2009 endangerment finding for all GHG emission standards for light-, medium-, and heavy-duty vehicles.

The rescission of the endangerment finding does not impact power plants, however, the EPA has also stated that, for other rules that have relied on the endangerment finding, it intends to initiate other rulemakings to address any overlapping issues.

Several environmental groups have filed a challenge to the EPA's repeal of the endangerment finding in the D.C.

Circuit Court.

Cross-State Air Pollution Rule (CSAPR) and Good Neighbor Plan

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

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

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

In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to lower the eight-hour standard for ozone emissions during ozone season (May to September), and, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA, which was then disapproved by the EPA in February 2023.

The State of Texas, Luminant, certain trade groups, and others challenged that disapproval in the U.S.

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

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

Circuit Court or have those challenges dismissed.

In March 2025, the Fifth Circuit Court denied those petitions for review, but we and the State of Texas have filed petitions for rehearing of that decision.

We do not expect any near-term impact to Texas sources from this decision.

Based on policy recent pronouncements from the Trump administration, the new EPA is reevaluating its approach to these Good Neighbor SIPs in general.

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

We, along with many other companies, trade groups, states, and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions.

In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP).

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

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

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

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

Circuit Court.

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

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

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

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

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

In 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.

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.

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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.

In April 2025, the D.C.

Circuit Court granted an abeyance of the case challenging the GNP FIP addressing interstate transport for all covered states while the EPA reviews the GNP FIP.

In January 2026, the EPA proposed removing eight states (although none that we operate in) from the GNP FIP, and we expect the EPA will take additional action to reconsider other aspects of the GNP FIP in 2026.

At this time, we do not know how these proposed changes could impact the overall trading program for any states that remain in the GNP FIP.

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

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

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

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

For NO X , the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas' SIP that determines that no electricity generation units are subject to BART for particulate matter.

In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019.

Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C.

Circuit Court, where we have intervened in support of the EPA.

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

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

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

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

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

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

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

However, that proposal was never finalized during the Biden administration.

In December 2025, the EPA issued a final rule for reasonable progress requirements that (a) approves portions of Texas' first planning period regional haze SIP and (b) approves Texas' second planning period regional haze SIP.

Under the EPA's rule, no new controls are required.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SO 2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants.

The final designations require Texas to develop nonattainment plans for these areas.

In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court.

In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable.

In May 2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring data supporting an attainment designation.

In June 2021, the EPA published two notices;

one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations.

We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, and this case was argued before the Fifth Circuit Court in July 2022.

In November 2016, the EPA finalized nonattainment designations for SO 2 for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants.

The final designations required Texas to develop nonattainment plans for these areas.

In 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.

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Emission reductions required are those necessary to demonstrate attainment with the NAAQS.

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

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

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

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

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

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

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

Based on 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.

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

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

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

In February 2022, we and the TCEQ entered into an agreed order to reduce SO 2 emissions at the Martin Lake plant, and the TCEQ submitted the agreed order to the EPA as a SIP revision to address the nonattainment designation.

We and the State of Texas had previously filed legal challenges in 2017 to the EPA's nonattainment designations in the Fifth Circuit Court.

In May 2025, the Fifth Circuit Court held that the EPA's designations were unlawful, granted the petitions for review, and remanded the designation back to the EPA.

In September 2025, the EPA issued a final rule withdrawing its Finding of Failure to Submit and Finding of Failure to Attain in light of the Fifth Circuit Court's May 2025 decision.

Effluent Limitation Guidelines (ELGs)

In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash, and flue gas mercury control wastewaters.

Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court.

In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines.

In April 2019, the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate.

The EPA published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency.

Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met.

In October 2020, the EPA published a final rule that extends the compliance date for both flue gas desulfurization (FGD) and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency.

Additionally, the rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met.

In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020.

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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.

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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.

In February 2025, the U.S.

Court of Appeals for the Eighth Circuit granted the EPA's unopposed motion seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

In December 2025, the EPA finalized additional revisions to the ELG rule, including extending certain compliance deadlines under the 2024 ELG rule.

Those deadlines would generally apply to facilities that had not already utilized the retirement provisions in the 2020 ELG rule, which our company had utilized.

In addition, the rule authorizes a process for states to extend the 2028 retirement deadline that was finalized as part of the 2020 ELG rule in the event market conditions would not support retirement of a facility.

We are currently evaluating this rule and the impact, if any, it might have on our announced plans to retire our remaining coal generation facilities in Illinois and Ohio by 2028 given that those facilities are under separate existing regulatory requirements to close by then.

Several environmental groups have recently challenged that rule.

Coal Combustion Residuals (CCR) Rule Revisions and Extension Applications

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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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Legacy CCR Rulemaking

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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.

Circuit Court granted an unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

In February 2026, the EPA issued a final rule for the CCRMU provisions of the rule extending the deadlines for the Facility Evaluation Reports (FER) to 2028, groundwater monitoring to 2031, and closure requirements to 2030.

The EPA has requested to keep the challenge to the rule addressing CCRMUs and legacy impoundments in abeyance.

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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We have completed closure activities at those ponds at our Baldwin facility.

At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C.

Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments ( i.e.

, the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014.

In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options.

In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General.

In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent order which the court subsequently entered.

Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter.

Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the Illinois Coal Ash regulation (discussed below) and close the site by removal.

At our retired Vermilion facility, in June 2021, we entered into an agreed interim consent order with the Illinois Attorney General and the Vermilion County State Attorney in which DMG is required to evaluate the closure alternatives under the requirements of the Illinois Coal Ash regulation (discussed below) and close the site by removal.

In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments.

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The rule does not mandate closure by removal at any site.

In May 2021, we, along with other industry petitioners, filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule.

In March 2024, the Illinois Fourth Judicial District issued a decision denying the industry petitions.

We do not anticipate any impacts from this decision.

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

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

In 2025, we filed construction permit applications (or supplemented prior operating permit applications) to cover corrective action activities at 11 impoundments across our Illinois fleet.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been approved by the IEPA and as such, an estimate of such costs cannot be made.

The CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the costs of closure methods that our operations and environmental services teams determined were appropriate based on the existing closure requirements at the time we recorded those ARO liabilities, and is reasonably possible for those to increase once the IEPA determines final closure requirements.

The CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the costs of closure methods that our operations and environmental services teams determined were appropriate based on the existing closure requirements at the time we recorded those ARO liabilities, and it is reasonably possible for those to increase once the IEPA determines final closure requirements.

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

MISO 2015-2016 Planning Resource Auction

In May 2015, three complaints were filed at the FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO.

Dynegy is a named party in one of the complaints.

The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc.

(Complainants), challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure going forward.

Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA.

The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding occurred.

The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by the Complainants.

We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff in connection with the PRA and disputing the allegations.

The Illinois Industrial Energy Consumers filed a related complaint at the FERC against MISO in June 2015 requesting prospective changes to the MISO tariff.

Dynegy also responded to this complaint with respect to Dynegy's conduct alleged in the complaint.

In October 2015, the FERC issued an order of nonpublic, formal investigation (the investigation) into whether market manipulation or other potential violations of the FERC orders, rules and regulations occurred before or during the PRA.

In December 2015, the FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction.

The order did not address the arguments of the Complainants regarding the PRA and stated that those issues remained under consideration and would be addressed in a future order.

In July 2019, the FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed.

The FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff.

A request for rehearing was denied by the FERC in March 2020.

The order was appealed by Public Citizen, Inc.

Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing Company intervened in the case in June 2020.

In August 2021, the D.C.

Circuit Court issued a ruling denying Public Citizen, Inc.'s arguments that the FERC failed to meet its obligation to ensure just and reasonable rates because it did not review the prices resulting from the auction before those prices went into effect and that the FERC was arbitrary and capricious in failing to adequately explain its decision to close its investigation into whether Dynegy engaged in market manipulation.

Circuit Court of Appeals granted Public Citizen, Inc.'s petition in part finding that the FERC's decision that the auction results were just and reasonable solely because the auction process complied with the filed tariff was unreasoned and remanded the case back to the FERC for further proceedings on that issue.

On February 4, 2022 the Illinois Attorney General and Public Citizen, Inc.

filed a motion at the FERC requesting that the FERC on remand reverse its prior decision and either find that auction results were not just and reasonable and order Dynegy to pay refunds to Illinois or, in the alternative, initiate an evidentiary hearing and discovery.

In June 2022, the FERC issued an order on remand establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 planning resource auction.

Although the FERC directed the Office of Enforcement to file a remand report, the FERC stated in the June 2022 order that it is not reopening the Office of Enforcement investigation.

In September 2022, the Office of Enforcement filed its remand report stating that the Office of Enforcement staff found during its investigation that Dynegy knowingly engaged in manipulative behavior to set the Zone 4 price in the 2015-2016 PRA.

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

In June 2024, the FERC issued an order for an evidentiary hearing (or a trial before a FERC administrative law judge) to determine what the FERC cited as "disputed issues of material fact" that it believes cannot be resolved on the existing record and, in October 2024, issued an order dismissing our request for rehearing of the June 2024 order.

We will continue to vigorously defend our position.

Other Matters

We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity, or financial condition.

Labor Contracts

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 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.

Nuclear Insurance

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

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

We maintain nuclear accident decontamination and reactor damage stabilization insurance and non-nuclear accident related property damage for our Beaver Valley, Davis-Besse and Perry facilities in the amount of $ 1.5 billion each (subject to a $ 20 million deductible per accident), and losses excluded or above such limits are self-insured.

We maintain nuclear accident decontamination and reactor damage stabilization insurance for our facilities in the amount of $ 2.25 billion and non-nuclear accident related property damage in the amount of $ 1.0 billion.

Coverage is subject to a $ 10 million deductible per accident including natural hazards except for the Davis-Besse facility which is subject to a $ 20 million deductible.

Losses excluded or above such limits are self-insured.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Coverage at Comanche Peak provides for weekly payments per unit up to $ 4.5 million for the first 52 weeks and up to $ 2.7 million for a remaining 21 weeks for non-nuclear and up to $ 3.6 million for a remaining 71 weeks for nuclear property damage outages.

The total maximum coverage is $ 291 million for non-nuclear property damage and $ 490 million for nuclear property damage outages.

Coverage at Beaver Valley, Davis-Besse and Perry facilities provide for weekly payments per unit up to $ 2.5 million for the first 52 weeks and up to $ 1.5 million for a remaining 52 weeks for non-nuclear and up to $ 2 million for a remaining 110 weeks for nuclear property damage outages.

The total maximum coverage is $ 208 million for non-nuclear property damage and $ 350 million for nuclear damage outages.

Coverage at the Comanche Peak, Beaver Valley, and Perry facilities provide 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 accident property damage and up to $ 3.6 million for a remaining 71 weeks for nuclear accident property damage outages.

The total maximum coverage is $ 291 million for non-nuclear accident property damage and $ 490 million for nuclear accident property damage outages.

Coverage at the Davis-Besse facility provides 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 accident property damage and up to $ 2 million for a remaining 110 weeks for nuclear accident property damage outages.

The total maximum coverage is $ 208 million for non-nuclear accident property damage and $ 350 million for nuclear accident property 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.

9 unchanged sentences

Shares issued (a) 5,117,434 — 5,117,434

Shares retired ( 18,391 ) — ( 18,391 )

Shares repurchased (b) — ( 16,560,328 ) ( 16,560,328 )

1 unchanged sentence

Shares issued (a) 4,917,325 — 4,917,325

Shares retired ( 10,771 ) — ( 10,771 )

Shares repurchased (b) — ( 6,550,237 ) ( 6,550,237 )

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In February 2026, the Board declared a quarterly dividend of $ 0.2280 per share of common stock that will be paid in March 2026.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Share Repurchase Program

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Board Authorization Dates:

October 2021 $ 2.00

August 2022 1.25

March 2023 1.00

February 2024 1.50

October 2024 1.00

Cumulative authorization at December 31, 2025

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(a) Shares repurchased include 7,828 of unsettled shares for $ 1 million as of December 31, 2025.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Preferred Stock

1 unchanged sentence

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

Preferred Stock Series Issuance

Date Shares Issued

Shares Outstanding

Rates Earliest Redemption Date (a)

Date at Which Dividend Rate Becomes Floating Floating Annual Rates

Series A October 15,

2021 1,000,000 1,000,000 8.000 % October 15,

2026 October 15,

2026 5 -Year U.S.

Treasury rate (subject to floor of 1.07 %) plus 6.93 %

Series B December 10,

2021 1,000,000 1,000,000 7.000 % December 15,

2026 December 15,

2026 5 -Year U.S.

Treasury rate (subject to floor of 1.26 %) plus 5.74 %

Series C December 29,

2023 476,081 476,066 8.875 % January 15,

2029 January 15,

2029 5 -Year U.S.

Treasury rate (subject to floor of 3.83 %) plus 5.045 %

(a) 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.

(a) Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.

Each series of preferred stock has a liquidation price of $ 1,000 , plus accrued and unpaid dividends through their redemption date.

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Preferred Stock Series 2025 2024 2023

2024 2023 2022

Series A Preferred Stock $ 80.00 $ 80.00 $ 80.00

$ 80.00 $ 80.00 $ 80.00

Series B Preferred Stock $ 70.00 $ 70.00 $ 70.00

$ 70.00 $ 70.00 $ 70.97

Series C Preferred Stock $ 88.75 $ 48.32

1 unchanged sentence

In February 2026, the Board declared a semi-annual dividend of $ 40.00 per share of Series A Preferred Stock that will be paid in April 2026.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EARNINGS PER SHARE

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(in millions, except share data)

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

Net income attributable to Vistra $ 944 $ 2,659 $ 1,493

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

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Less cumulative dividends attributable to Series C Preferred Stock ( 42 ) ( 42 ) —

Net income (loss) attributable to common stock — basic and diluted 2,467 1,343 ( 1,377 )

Net income attributable to common stock — basic and diluted 752 2,467 1,343

Weighted average shares of common stock outstanding:

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Diluted $ 2.18 $ 7.00 $ 3.58

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

Vistra 2016 Omnibus Incentive Plan

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:

Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation.

No awards under the 2016 Incentive Plan have been settled in cash since the Effective Date.

Stock-Based Compensation Expense

Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows:

Year Ended December 31,

2024 2023 2022

(in millions)

Total stock-based compensation expense $ 100 $ 77 $ 65

Income tax benefit ( 23 ) ( 18 ) ( 15 )

Stock based-compensation expense, net of tax $ 77 $ 59 $ 50

Stock Options

Stock options outstanding at December 31, 2024 are all held by current or former employees.

The following table summarizes our stock option activity:

Year Ended December 31, 2024

Stock Options

(in thousands) Weighted

Average Exercise Price Weighted Average Remaining Contractual Term (Years) Aggregate Intrinsic Value (in millions)

Total outstanding at beginning of period 6,126 $ 20.01 4.2 $ 113.5

Exercised ( 2,526 ) $ 20.06

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, 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

The following table summarizes our restricted stock unit activity:

Year Ended December 31, 2024

Restricted Stock Units

(in thousands) Weighted

Average Grant Date Fair Value

Total nonvested at beginning of period 3,908 $ 21.90

Granted 1,017 $ 59.11

Vested ( 1,785 ) $ 22.20

Forfeited ( 86 ) $ 33.55

Total nonvested at end of period 3,054 $ 34.30

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.

All PSUs have a three year performance period and a payout opportunity of 0 - 200 % of target ( 100 %), which is intended to be settled in shares of Vistra common stock.

We recognized compensation expense associated with PSUs of $ 54 million, $ 36 million, and $ 22 million for the years ended December 31, 2024, 2023, and 2022, respectively.

As of December 31, 2024, we have $ 64 million of unrecognized compensation cost associated with PSUs.

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 years ended December 31, 2025 and 2024 and totaled 392,218 shares in the year ended December 31, 2023.

SEGMENT INFORMATION

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(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.

Our Chief Executive Officer is our chief operating decision maker (CODM).

Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations.

A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources.

The results of the plants previously included in the Sunset segment are now reflected in the Texas and East segments based on their respective geographies.

The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial, and industrial customers.

Substantially all of these activities are conducted by TXU Energy, Ambit, Dynegy Energy Services, Homefield Energy, Energy Harbor, and U.S.

Substantially all of these activities are conducted by TXU Energy, Ambit Energy, 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 Texas segment represents results from all of Vistra's electricity generation operations in the ERCOT market except for assets included in the Asset Closure segment.

The East segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S.

electric grid, other than assets included in the Asset Closure segment, and includes operations in the PJM, MISO, ISO-NE, and NYISO markets.

The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site.

The 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.

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 West segment represents results from the CAISO market, including our battery ESS project at our Moss Landing power plant site.

The Moss Landing 300 MW and Moss Landing 100 MW battery facilities were transferred to the Asset Closure segment in the first quarter of 2025 and fourth quarter of 2025, respectively, as a result of the Moss Landing Incident (see Note 8 for additional information).

Management concluded that the 2023 and 2024 revenues, expenses, and capital expenditures associated with the Moss Landing 100 MW battery were immaterial, therefore, prior‑period segment results have not been recast.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Asset Closure segment is engaged in the decommissioning and reclamation of retired generation facilities, including mines, and battery removal and remediation activities.

When facilities are transferred to the Asset Closure segment, prior period results are retrospectively adjusted for comparative purposes, provided the effects are material (see Note 7 for additional information).

By separately reporting the Asset Closure segment, management gains improved insights into the performance and earnings potential of Vistra's ongoing operations while actively monitoring the cost associated with Asset Closure activities.

Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes, other expenses, and nuclear fuel cash capital expenditures not allocated to our operating segments.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1.

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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.

The CODM uses net income in competitive analysis by benchmarking to the Company's competitors and evaluating drivers of segment profits available to the Company's equity holders.

We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices.

2 unchanged sentences

Year Ended December 31, 2025

Asset Closure

Retail Texas East West Asset Closure

Total Reportable Segments

Corporate and Other

(in millions)

Operating revenues

Operating revenues (a)

$ 14,340 $ 5,353 $ 6,174 $ 325 $ 74 $ 26,266

Fuel, purchased power costs, and delivery fees

Reconciliation of consolidated operating revenues:

Corporate and Other

Total consolidated operating revenues

Fuel, purchased power costs, and delivery fees (b)

( 11,686 ) ( 1,990 ) ( 3,807 ) ( 149 ) —

Operating costs ( 168 ) ( 1,050 ) ( 1,381 ) ( 59 ) ( 154 )

( 159 ) ( 996 ) ( 1,103 ) ( 72 ) ( 81 ) ( 2,411 ) ( 3 ) ( 2,414 )

Selling, general, and administrative expenses ( 1,035 ) ( 180 ) ( 235 ) ( 14 ) ( 66 )

( 977 ) ( 169 ) ( 148 ) ( 25 ) ( 43 ) ( 1,362 ) ( 239 ) ( 1,601 )

Other segment items:

Depreciation and amortization ( 94 ) ( 638 ) ( 1,120 ) ( 61 ) 2

( 114 ) ( 581 ) ( 996 ) ( 86 ) — ( 1,777 ) ( 66 ) ( 1,843 )

Interest expenses and related charges ( 67 ) 53 50 7 ( 4 )

1 unchanged sentence

— — ( 1 ) — —

Net income (loss)

— 56 229 5 ( 131 )

Total reportable segment net income (loss)

$ 1,290 $ 1,604 $ ( 91 ) $ 54 $ ( 279 ) $ 2,578

Reconciliation to consolidated income before income taxes:

Corporate and Other - net loss

Corporate and Other - income tax expense

Total consolidated income before income taxes

Capital expenditures, including nuclear fuel and excluding growth expenditures

$ 12 $ 954 $ 647 $ 186 $ — $ 1,799

Reconciliation to consolidated capital expenditures, including nuclear fuel and excluding growth expenditures

Corporate and Other - nuclear fuel net purchases

Total capital expenditures, including nuclear fuel and excluding growth expenditures

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(a) See Note 3 for disaggregated revenue by segment.

Includes intersegment sales eliminated in Corporate and Other.

(b) Includes nuclear fuel amortization of $ 133 million and $ 354 million, respectively, in the Texas and East segments.

Year Ended December 31, 2024

Asset Closure (b)

Retail Texas East West Asset Closure

Total Reportable Segments

Corporate and Other

(in millions)

Operating revenues

Operating revenues (a)

$ 12,797 $ 5,394 $ 5,661 $ 839 $ 39 $ 24,730

Fuel, purchased power costs, and delivery fees

Reconciliation of consolidated operating revenues:

Corporate and Other

Total consolidated operating revenues $ 17,224

Fuel, purchased power costs, and delivery fees (b)

( 10,276 ) ( 1,596 ) ( 2,698 ) ( 218 ) ( 6 )

Operating costs ( 159 ) ( 996 ) ( 1,103 ) ( 52 ) ( 101 )

( 123 ) ( 917 ) ( 528 ) ( 58 ) ( 74 ) ( 1,700 ) ( 2 ) ( 1,702 )

Selling, general, and administrative expenses ( 977 ) ( 169 ) ( 148 ) ( 20 ) ( 48 )

( 858 ) ( 140 ) ( 127 ) ( 24 ) ( 34 ) ( 1,183 ) ( 125 ) ( 1,308 )

Other segment items:

Depreciation and amortization ( 114 ) ( 581 ) ( 996 ) ( 58 ) ( 28 )

( 102 ) ( 550 ) ( 703 ) ( 79 ) — ( 1,434 ) ( 68 ) ( 1,502 )

Interest expenses and related charges ( 54 ) 46 9 1 ( 4 )

Income tax expense — — ( 1 ) — — ( 1 ) ( 507 ) ( 508 )

( 1 ) 35 177 ( 6 ) 17

Net income (loss)

$ 424 $ 398 $ 1,749 $ 454 $ ( 6 ) $ 3,019 $ ( 1,527 ) $ 1,492

Total reportable segment net income (loss) $ 1,216 $ 2,133 $ 902 $ 486 $ ( 131 ) $ 4,606

Reconciliation to consolidated income before income taxes:

Corporate and Other - net loss

Corporate and Other - income tax expense

Total consolidated income before income taxes $ 3,467

Capital expenditures, including nuclear fuel and excluding growth expenditures

$ 4 $ 751 $ 557 $ 68 $ 2 $ 1,382

Reconciliation to consolidated capital expenditures, including nuclear fuel and excluding growth expenditures

Corporate and Other - nuclear fuel net purchases

Total capital expenditures, including nuclear fuel and excluding growth expenditures $ 1,727

(a) See Note 3 for disaggregated revenue by segment.

Includes intersegment sales eliminated in Corporate and Other.

(b) Includes nuclear fuel amortization of $ 105 million and $ 282 million, respectively, in the Texas and East segments.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31, 2023

Asset Closure (b)

Retail Texas East West Asset Closure

Total Reportable Segments

Corporate and Other

(in millions)

Operating revenues

Operating revenues (a)

$ 10,572 $ 3,979 $ 5,890 $ 866 $ 48 $ 21,355

Reconciliation of consolidated operating revenues:

Corporate and Other

Total consolidated operating revenues $ 14,779

Fuel, purchased power costs, and delivery fees ( 9,046 ) ( 2,028 ) ( 2,730 ) ( 326 ) ( 5 )

( 7,169 ) ( 3,052 ) ( 4,132 ) ( 481 ) ( 322 ) ( 15,156 ) 4,755 ( 10,401 )

Operating costs ( 123 ) ( 917 ) ( 528 ) ( 42 ) ( 90 )

( 143 ) ( 832 ) ( 482 ) ( 42 ) ( 145 ) ( 1,644 ) ( 1 ) ( 1,645 )

Selling, general, and administrative expenses ( 858 ) ( 140 ) ( 127 ) ( 22 ) ( 36 )

( 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 ( 102 ) ( 550 ) ( 703 ) ( 52 ) ( 27 )

( 145 ) ( 541 ) ( 768 ) ( 42 ) ( 31 ) ( 1,527 ) ( 69 ) ( 1,596 )

Income tax benefit — — — — — — 350 350

Interest expenses and related charges ( 20 ) 21 ( 2 ) 8 ( 5 )

Income tax expense

— — ( 1 ) — —

Net income (loss)

1 33 ( 50 ) 2 129

Total reportable segment net income (loss) $ 424 $ 398 $ 1,749 $ 434 $ 14 $ 3,019

Reconciliation to consolidated income before income taxes:

Corporate and Other - net loss

Corporate and Other - income tax expense

Total consolidated income before income taxes $ 2,000

Capital expenditures, including nuclear fuel and excluding growth expenditures

$ 1 $ 536 $ 362 $ 364 $ 2 $ 1,265

(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

Year Ended December 31,

2024 2023 2022

(in millions)

Other income:

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

All other 38 23 20

Total other income $ 312 $ 257 $ 117

Other deductions:

All other $ 21 $ 14 $ 4

Total other deductions $ 21 $ 14 $ 4

(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, 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

Fuel stock 403 420

Natural gas in storage 34 31

Total inventories $ 970 $ 740

(in millions)

Nuclear decommissioning trusts $ 4,440 $ 1,951

Assets related to employee benefit plans 14 28

Land investments 42 42

Other investments 16 14

Total investments $ 4,512 $ 2,035

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)

Winter Storm Uri impact (a) 1 26

Identifiable intangible liabilities (Note 7)

Regulatory liability (b) 452 209

Operating lease liabilities 98 48

Finance lease liabilities 218 227

Liability for third-party remediation 8 17

Accrued severance costs 36 36

Other accrued expenses 64 58

Total other noncurrent liabilities and deferred credits $ 1,256 $ 999

(a) Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.

(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 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 (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:

Interest paid $ 987 $ 636 $ 581

Capitalized interest ( 77 ) ( 37 ) ( 29 )

Interest paid (net of capitalized interest) $ 910 $ 599 $ 552

Non-cash investing and financing activities:

Accrued property, plant, and equipment additions (a) $ 258 $ 104 $ 103

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, 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.

Reconciliation to consolidated capital expenditures, including nuclear fuel and excluding growth expenditures

Corporate and Other - nuclear fuel net purchases

Total capital expenditures, including nuclear fuel and excluding growth expenditures $ 1,471

(a) See Note 3 for disaggregated revenue by segment.

Includes intersegment sales eliminated in Corporate and Other.

(b) Other includes impairment of long-lived assets, other income, net and the impacts of the Tax Receivable Agreement.

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