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  4. [10-Q] Vistra Corp. Quarterly Earnings Report

[10-Q] Vistra Corp. Quarterly Earnings Report

Filing Impact
(Neutral)
Filing Sentiment
(Neutral)
Form Type
10-Q
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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2025

— OR —
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __ to __


Commission File Number 001-38086

Vistra Corp.

(Exact name of registrant as specified in its charter)
Delaware
36-4833255
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
6555 Sierra Drive,
Irving,
Texas
75039(214)812-4600
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common stock, par value $0.01 per shareVST
New York Stock Exchange
NYSE Texas

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.   Yes ☒    No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes ☒    No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒  Accelerated filer ☐  Non-accelerated filer ☐ Smaller reporting company ☐  Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes  ☐ No ☒

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Class
Outstanding as of October 31, 2025
Common stock, par value $0.01 per share338,825,490


Table of Contents
TABLE OF CONTENTS
PAGE
Glossary of Terms and Abbreviations
i
Forward-Looking Statements
v
PART I.
FINANCIAL INFORMATION
1
Item 1.
Financial Statements (Unaudited)
1
Condensed Consolidated Statements of Operations
1
Condensed Consolidated Statements of Comprehensive Income (Loss)
1
Condensed Consolidated Balance Sheets
2
Condensed Consolidated Statements of Cash Flows
4
Condensed Consolidated Statements of Changes in Equity
6
Notes to Condensed Consolidated Financial Statements
9
1. Business, Significant Accounting Policies, Significant Events, and Recent Developments
9
2. Acquisitions
12
3. Revenue
16
4. Government Assistance
20
5. Income Taxes
20
6. Property, Plant, and Equipment
21
7. Goodwill and Identifiable Intangible Assets and Liabilities
22
8. Collateral Financing Agreement with Affiliate
24
9. Debt, Credit Facilities, and Financings
24
10. Derivatives
33
11. Fair Value Measurements
37
12. Asset Retirement Obligations
42
13. Commitments and Contingencies
43
14. Equity
50
15. Earnings Per Share
51
16. Segment Information
52
17. Supplementary Financial Information
55
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
57
Significant Activities and Events, and Items Influencing Future Performance
57
Critical Accounting Policies and Estimates
61
Results of Operations
61
Financial Condition
72
Commitments and Contingencies
77
Changes in Accounting Standards
77
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
77
Item 4.
Controls and Procedures
79
PART II.
OTHER INFORMATION
80
Item 1.
Legal Proceedings
80
Item 1A.
Risk Factors
80
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
80
Item 3.
Defaults Upon Senior Securities
80
Item 4.
Mine Safety Disclosures
81
Item 5.
Other Information
81
Item 6.
Exhibits
81
SIGNATURE
83

i
Table of Contents
GLOSSARY OF TERMS AND ABBREVIATIONS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Current and Former Related Entities:
AmbitAmbit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context
Ambit TexasAmbit Texas, LLC, a wholly owned subsidiary of Vistra
BCOP
BCOP Borrower LLC, a subsidiary of Vistra Zero
DynegyDynegy Inc., and/or its subsidiaries, depending on context
Dynegy Energy Services
Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (each d/b/a Dynegy, Better Buy Energy, Brighten Energy, Honor Energy and True Fit Energy), indirect, wholly owned subsidiaries of Vistra, that are REPs in certain areas of MISO and PJM, respectively, and are engaged in the retail sale of electricity to residential and business customers.
Energy HarborEnergy Harbor Holdings LLC (formerly known as Energy Harbor Corp.), and/or its subsidiaries, depending on context
Homefield Energy
Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of MISO that is engaged in the retail sale of electricity to municipal customers
Lotus
Lotus Infrastructure Partners
Luminantsubsidiaries of Vistra engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management
ParentVistra Corp.
TriEagle Energy
TriEagle Energy, LP (d/b/a TriEagle Energy, TriEagle Energy Services, Eagle Energy, Energy Rewards, Power House Energy and Viridian Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of ERCOT and PJM that is engaged in the retail sale of electricity to residential and business customers
TXU Energy
TXU Energy Retail Company LLC (d/b/a TXU), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
U.S. Gas & Electric
U.S. Gas and Electric, LLC (d/b/a USG&E, Illinois Gas & Electric and ILG&E), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers
Value Based Brands
Value Based Brands LLC (d/b/a 4Change Energy, Express Energy and Veteran Energy), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
VistraVistra Corp., and/or its subsidiaries, depending on context
Vistra IntermediateVistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra
Vistra Operations
Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the issuer of certain series of notes (see Note 9 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
Vistra VisionVistra Vision LLC, an indirect subsidiary of Vistra
Vistra Zero
subsidiaries of Vistra engaged in the operation and development of renewables and energy storage assets
Vistra Zero Operating
Vistra Zero Operating Company, LLC, an indirect, wholly owned subsidiary of Vistra
Transmission System Operators:
CAISOThe California Independent System Operator
ERCOTElectric Reliability Council of Texas, Inc.
ISO-NEISO New England Inc.
MISOMidcontinent Independent System Operator, Inc.
NYISONew York Independent System Operator, Inc.
PJMPJM Interconnection, LLC
Authoritative Organizations:
EPAU.S. Environmental Protection Agency
FERCU.S. Federal Energy Regulatory Commission
IEPAIllinois Environmental Protection Agency
ii
Table of Contents
IPCBIllinois Pollution Control Board
IRSU.S. Internal Revenue Service
MSHAU.S. Mine Safety and Health Administration
NRCU.S. Nuclear Regulatory Commission
PUCTPublic Utility Commission of Texas
RCTRailroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas, and has jurisdiction over oil and natural gas exploration and production, permitting and inspecting intrastate pipelines, and overseeing natural gas utility rates and compliance
SECU.S. Securities and Exchange Commission
TCEQTexas Commission on Environmental Quality
Rules and Regulations:
Exchange ActSecurities Exchange Act of 1934, as amended
IRAInflation Reduction Act of 2022
OBBBAOne Big Beautiful Bill Act
Securities ActSecurities Act of 1933, as amended
General Terms:
2024 Form 10-K
Vistra's annual report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 28, 2025
AROasset retirement and mining reclamation obligation
BCOP Credit Agreement
credit agreement, dated as of December 16, 2024 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among BCOP, the lenders and issuing banks party thereto, the administrative agent, and collateral agent and the other parties named therein
CCGTcombined cycle natural gas turbine
CCRcoal combustion residuals
CMEChicago Mercantile Exchange
EBITDAearnings (net income) before interest expense, income taxes, depreciation and amortization
ERPenterprise resource program
ESSenergy storage system
GAAPgenerally accepted accounting principles
GHGgreenhouse gas
GWhgigawatt-hours
Heat RateHeat Rate is a measure of the efficiency of converting a fuel source to electricity
ISOindependent system operator
ITCinvestment tax credit
loaddemand for electricity
LTSAlong-term service agreements for plant maintenance
Market Heat Rate
Market Heat Rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier (generally natural gas plants), by the market price of natural gas
MMBtumillion British thermal units
MWmegawatts
MWhmegawatt-hours
NYMEXthe New York Mercantile Exchange, a commodity derivatives exchange
PTCproduction tax credit
REPretail electric provider
RTOregional transmission organization
S&PStandard & Poor's Ratings (a credit rating agency)
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Series A Preferred StockVistra's 8.0% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
Series B Preferred StockVistra's 7.0% Series B Fixed-Rate Reset Cumulative Green Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
Series C Preferred StockVistra's 8.875% Series C Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
SG&A
selling, general, and administrative
SO2
sulfur dioxide
SOFRSecured Overnight Financing Rate, the average rate at which institutions can borrow U.S. dollars overnight while posting U.S. Treasury Bonds as collateral
TRA
Amended and Restated Tax Receivable Agreement, containing certain rights (TRA Rights) to receive payments from Vistra related to certain tax benefits, including benefits realized as a result of certain transactions entered into at the emergence of our predecessor from reorganization under Chapter 11 of the U.S. Bankruptcy Code
U.S.United States of America
Vistra Operations Commodity-Linked Credit Agreement
credit agreement, dated as of February 4, 2022 (as amended, restated, amended and restated, supplemented, and/or otherwise modified from time to time) by and among Vistra Operations, Vistra Intermediate, the lenders party thereto, the other credit parties thereto, the administrative agent, the collateral agent, and the other parties named therein
Vistra Operations Credit Agreement
credit agreement, dated as of October 3, 2016 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among Vistra Operations, Vistra Intermediate, the lenders party thereto, the letter of credit issuers party thereto, the administrative agent, the collateral agent, and the other parties named therein
Vistra Operations Credit Facilities
Vistra Operations senior secured financing facilities
Vistra Zero Credit Agreement
credit agreement, dated as of March 26, 2024 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among Vistra Zero Operating, the lenders party thereto, the administrative agent, and collateral agent, and the other parties named therein

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FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains forward-looking statements that involve risk and uncertainties. All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including (without limitation) such matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments, and the growth of our businesses and operations, including potential transactions with large load facilities at our nuclear and natural gas plants (often, but not always, through the use of words or phrases such as "intends," "plans," "potential," "will likely," "unlikely," "believe," "expect," "anticipated," "estimate," "should," "could," "may," "projection," "forecast," "target," "goal," "objective," and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and risks which could cause our actual results to differ materially from those projected in or implied by such forward looking statements. Any such forward-looking statement is qualified in its entirety by reference to the discussion in (i) Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations in our 2024 Form 10-K, and (ii) Part I, Item 2 Management's Discussion and Analysis of Financial Condition, and Results of Operations in this quarterly report on Form 10-Q.

Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events or circumstances. New factors emerge from time to time, and it is not possible for us to predict them. In addition, we may be unable to assess the impact of any such event or condition or the extent to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.
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PART I. FINANCIAL INFORMATION

Item 1.FINANCIAL STATEMENTS

VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited) (Millions of Dollars, Except Share Data)
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
Operating revenues$4,971 $6,288 $13,154 $13,187 
Fuel, purchased power costs, and delivery fees(2,370)(2,207)(6,791)(5,520)
Operating costs(655)(616)(2,081)(1,742)
Depreciation and amortization(460)(466)(1,523)(1,306)
Selling, general, and administrative expenses(444)(411)(1,254)(1,137)
Impairment of long-lived assets(5)— (73)— 
Operating income1,037 2,588 1,432 3,482 
Other income, net105 136 291 282 
Interest expense and related charges(286)(332)(908)(743)
Impacts of Tax Receivable Agreement— — — (5)
Net income before income taxes856 2,392 815 3,016 
Income tax expense(204)(555)(104)(694)
Net income$652 $1,837 $711 $2,322 
Net (income) loss attributable to noncontrolling interest— 51 — (104)
Net income attributable to Vistra$652 $1,888 $711 $2,218 
Cumulative dividends attributable to preferred stock(48)(48)(144)(144)
Net income attributable to Vistra common stock$604 $1,840 $567 $2,074 
Weighted average shares of common stock outstanding:
Basic338,749,454 342,969,916 339,313,294 346,315,125 
Diluted345,035,160 350,203,692 346,303,617 353,805,937 
Net income per weighted average share of common stock outstanding:
Basic$1.78 $5.36 $1.67 $5.99 
Diluted$1.75 $5.25 $1.64 $5.86 

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited) (Millions of Dollars)
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
Net income$652 $1,837 $711 $2,322 
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense of $—, $—, $— and $—)
1 1 — 1 
Total other comprehensive income1 1 — 1 
Comprehensive income$653 $1,838 $711 $2,323 
Comprehensive (income) loss attributable to noncontrolling interest— 51 — (104)
Comprehensive income attributable to Vistra$653 $1,889 $711 $2,219 

See Notes to Condensed Consolidated Financial Statements
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VISTRA CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) (Millions of Dollars, Except Share Data)
September 30, 2025December 31,
2024
ASSETS
Current assets:
Cash and cash equivalents$602 $1,188 
Restricted cash30 28 
Trade accounts receivable — net2,327 1,982 
Inventories970 970 
Commodity and other derivative contractual assets2,634 2,587 
Margin deposits related to commodity contracts721 406 
Margin deposits posted under affiliate financing agreement450 435 
Prepaid expense and other current assets647 523 
Total current assets8,381 8,119 
Restricted cash 6 6 
Investments5,008 4,512 
Property, plant and equipment — net17,725 18,173 
Goodwill2,810 2,807 
Identifiable intangible assets — net2,097 2,213 
Commodity and other derivative contractual assets 604 740 
Accumulated deferred income taxes9 9 
Other noncurrent assets1,380 1,191 
Total assets$38,020 $37,770 
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable financing$1,225 $750 
Long-term debt due currently231 880 
Forward repurchase obligation due currently701 703 
Trade accounts payable1,362 1,510 
Commodity and other derivative contractual liabilities3,610 3,351 
Margin deposits related to commodity contracts 3 49 
Accrued taxes other than income180 209 
Accrued interest225 193 
Asset retirement obligations202 142 
Other current liabilities687 645 
Total current liabilities8,426 8,432 
Margin deposits financing with affiliate450 435 
Long-term debt, less amounts due currently15,757 15,418 
Forward repurchase obligation, less amounts due currently613 632 
Commodity and other derivative contractual liabilities1,388 1,367 
Accumulated deferred income taxes 765 697 
Asset retirement obligations 3,944 3,936 
Other noncurrent liabilities and deferred credits1,454 1,270 
Total liabilities32,797 32,187 
See Notes to Condensed Consolidated Financial Statements
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VISTRA CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) (Millions of Dollars, Except Share Data)
September 30, 2025December 31,
2024
Commitments and Contingencies
Total equity:
Preferred stock (100,000,000 shares authorized, $1,000 liquidation preference per share, 2,476,066 shares outstanding at both September 30, 2025 and December 31, 2024, respectively)
2,476 2,476 
Common stock (par value $0.01 per share, 1,800,000,000 shares authorized, 338,679,644 and 339,754,307 shares outstanding at September 30, 2025 and December 31, 2024, respectively)
5 5 
Treasury stock, at cost (214,210,252 and 208,998,299 shares at September 30, 2025 and December 31, 2024, respectively)
(6,675)(5,912)
Additional paid-in-capital9,491 9,435 
Accumulated deficit(107)(454)
Accumulated other comprehensive income20 20 
Stockholders' equity5,210 5,570 
Noncontrolling interest in subsidiary13 13 
Total equity5,223 5,583 
Total liabilities and equity$38,020 $37,770 

See Notes to Condensed Consolidated Financial Statements
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VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) (Millions of Dollars)
Nine Months Ended September 30,
20252024
Cash flows — operating activities:
Net income$711 $2,322 
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization2,225 1,891 
Deferred income tax expense (benefit), net68 666 
Impairment of long-lived and other assets73 — 
Unrealized net (gain) loss from mark-to-market valuations of commodities367 (1,725)
Unrealized net loss from mark-to-market valuations of interest rate swaps84 26 
Unrealized net gain from nuclear decommissioning trusts(164)(133)
Asset retirement obligation accretion expense100 84 
Bad debt expense152 132 
Stock-based compensation expense82 76 
Involuntary conversion gain(80)— 
Other, net36 (14)
Changes in operating assets and liabilities:
Margin deposits, net(361)855 
Accrued interest32 11 
Accrued taxes(19)(40)
Accrued employee incentive(106)(78)
Other operating assets and liabilities(562)(863)
Cash provided by operating activities2,638 3,210 
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments(1,916)(1,648)
Energy Harbor acquisition (net of cash acquired)— (3,065)
Proceeds from sales of nuclear decommissioning trust fund securities4,120 1,573 
Investments in nuclear decommissioning trust fund securities(4,138)(1,590)
Proceeds from sales of environmental allowances57 147 
Purchases of environmental allowances(511)(511)
Insurance proceeds for recovery of damaged property, plant and equipment198 3 
Proceeds from sale of property, plant and equipment, including nuclear fuel21 137 
Other, net7 (5)
Cash used in investing activities(2,162)(4,959)
Cash flows — financing activities:
Issuances of debt424 2,200 
Repayments/repurchases of debt(764)(2,269)
Net borrowings under accounts receivable financing475 750 
Borrowings under Revolving Credit Facility150 50 
Repayments under Revolving Credit Facility(150)(50)
Borrowings under Commodity-Linked Facility987 1,802 
Repayments under Commodity-Linked Facility(987)(1,802)
Debt issuance costs(2)(32)
Stock repurchases(776)(1,021)
Dividends paid to common stockholders(229)(230)
Dividends paid to preferred stockholders(117)(98)
Dividends paid to noncontrolling interest holders— (15)
See Notes to Condensed Consolidated Financial Statements
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VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) (Millions of Dollars)
Nine Months Ended September 30,
20252024
Tax withholding on stock based compensation(51)(11)
Principal payment on forward repurchase obligation(41)— 
TRA Repurchase and tender offer — return of capital— (122)
Other, net21 (2)
Cash used in financing activities(1,060)(850)
Net change in cash, cash equivalents and restricted cash(584)(2,599)
Cash, cash equivalents and restricted cash — beginning balance1,222 3,539 
Cash, cash equivalents and restricted cash — ending balance$638 $940 
See Notes to Condensed Consolidated Financial Statements
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VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited) (Millions of Dollars)
Preferred StockCommon StockTreasury StockAdditional Paid-In CapitalAccumulated DeficitAccumulated Other Comprehensive IncomeTotal Stockholders' EquityNoncontrolling Interest in SubsidiaryTotal Equity
Balances at
December 31, 2024
$2,476 $5 $(5,912)$9,435 $(454)$20 $5,570 $13 $5,583 
Stock repurchases— — (336)— — — (336)— (336)
Effects of stock-based incentive compensation plans (a)— — — (27)— — (27)— (27)
Net loss— — — — (268)— (268)— (268)
Dividends declared on common stock— — — — (75)— (75)— (75)
Dividends declared on preferred stock— — — — (38)— (38)— (38)
Other— — — (1)— — (1)— (1)
Balances at
March 31, 2025		$2,476 $5 $(6,248)$9,407 $(835)$20 $4,825 $13 $4,838 
Stock repurchases— — (237)— — — (237)— (237)
Effects of stock-based incentive compensation plans— — — 43 — — 43 — 43 
Net income— — — — 327 — 327 — 327 
Dividends declared on common stock— — — — (77)— (77)— (77)
Dividends declared on preferred stock— — — — (58)— (58)— (58)
Change in accumulated other comprehensive income— — — — — (1)(1)— (1)
Other— — — — 1 — 1 — 1 
Balances at
June 30, 2025		$2,476 $5 $(6,485)$9,450 $(642)$19 $4,823 $13 $4,836 
Stock repurchases— — (190)— — — (190)— (190)
Effects of stock-based incentive compensation plans— — — 42 — — 42 — 42 
Net income
— — — — 652 — 652 — 652 
Dividends declared on common stock— — — — (79)— (79)— (79)
Dividends declared on preferred stock— — — — (39)— (39)— (39)
Change in accumulated other comprehensive income— — — — — 1 1 — 1 
Other— — — (1)1 — — — — 
Balances at
September 30, 2025		$2,476 $5 $(6,675)$9,491 $(107)$20 $5,210 $13 $5,223 

See Notes to Condensed Consolidated Financial Statements
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VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (CONTINUED)
(Unaudited) (Millions of Dollars)
Preferred StockCommon StockTreasury StockAdditional Paid-In CapitalAccumulated DeficitAccumulated Other Comprehensive IncomeTotal Stockholders' EquityNoncontrolling Interest in SubsidiaryTotal Equity
Balances at
December 31, 2023
$2,476 $5 $(4,662)$10,095 $(2,613)$6 $5,307 $15 $5,322 
Stock repurchases— — (285)— — — (285)— (285)
Effects of stock-based incentive compensation plans (a)— — — 35 — — 35 — 35 
Equity issued in subsidiary to acquire Energy Harbor (b)— — — 747 — — 747 1,560 2,307 
Net income (loss)— — — — (35)— (35)53 18 
Dividends declared on common stock— — — — (77)— (77)— (77)
Dividends declared on preferred stock— — — — (37)— (37)— (37)
Other— — — 1 — — 1 — 1 
Balances at
March 31, 2024		$2,476 $5 $(4,947)$10,878 $(2,762)$6 $5,656 $1,628 $7,284 
Stock repurchases— — (331)— — — (331)— (331)
Effects of stock-based incentive compensation plans— — — 40 — — 40 — 40 
Net income— — — — 365 — 365 102 467 
Dividends declared on common stock— — — — (77)— (77)— (77)
Dividends declared on preferred stock— — — — (59)— (59)— (59)
Dividends to noncontrolling interest— — — — — — — (15)(15)
Other— — — (1)— — (1)(1)(2)
Balances at
June 30, 2024		$2,476 $5 $(5,278)$10,917 $(2,533)$6 $5,593 $1,714 $7,307 
Stock repurchases— — (406)— — — (406)— (406)
Effects of stock-based incentive compensation plans— — — 28 — — 28 — 28 
Net income— — — — 1,888 — 1,888 (51)1,837 
Dividends declared on common stock— — — — (76)— (76)— (76)
Dividends declared on preferred stock— — — — (39)— (39)— (39)
Change in accumulated other comprehensive income— — — — — 1 1 — 1 
Modification of noncontrolling interest to redeemable noncontrolling interest (b)— — — (1,539)— — (1,539)(1,659)(3,198)
Other— — — (10)1 — (9)10 1 
Balances at
September 30, 2024
$2,476 $5 $(5,684)$9,396 $(759)$7 $5,441 $14 $5,455 
See Notes to Condensed Consolidated Financial Statements
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____________
(a)Includes cash payments to cover tax withholding obligations upon the vesting of stock-based incentive compensation plans of $50 million and $12 million for the three months ended March 31, 2025 and 2024, respectively.
(b)See Note 2 for additional information regarding activity associated with noncontrolling interest.
See Notes to Condensed Consolidated Financial Statements
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VISTRA CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.BUSINESS, SIGNIFICANT ACCOUNTING POLICIES, SIGNIFICANT EVENTS, AND RECENT DEVELOPMENTS

Description of Business

References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary of Terms and Abbreviations for defined terms.

Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management, and retail sales of electricity and natural gas to end users.

Vistra has five reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. See Note 16 for additional information.

Significant Accounting Policies

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2024 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. The condensed consolidated financial information herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. Certain prior period amounts have been reclassified to conform with the current year presentation.

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities as of the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgments related to the potential timing of events, and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.

Recent Accounting Pronouncements

Improvements to Income Tax Disclosures

In December 2023, the FASB issued Accounting Standards Update (ASU) No. 2023-09 (ASU 2023-09), Income Taxes (Topic 740): Improvements to Income Tax Disclosures to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. The amendments only apply to income tax disclosures and we do not expect adoption to have a material impact on our consolidated financial statements.

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Expense Disaggregation Disclosures

In November 2024, the FASB issued ASU No. 2024-03 (ASU 2024-03), Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve disclosures by providing additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and interim periods within annual reporting periods beginning after December 15, 2027 and can be applied prospectively or retrospectively. Early adoption is permitted. We are currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures.

Significant Events

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, but the two other battery facilities remain offline as we continue to investigate the cause of the fire. We expect the Moss Landing 350 MW battery to return to service in late 2025 or early 2026. There is less certainty about the return to service regarding the Moss Landing 100 MW battery. We will know more after the investigation of the cause of the Moss Landing Incident is complete. As of September 30, 2025, the net book value of the Moss Landing 100 facility was approximately $165 million.

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 6 and 16 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 $29 million on ASAOC activities through September 30, 2025. As of September 30, 2025, our accrual for estimated future costs for the ASAOC activities is approximately $81 million, of which, $68 million is reflected in other current liabilities and $13 million is reflected in other noncurrent liabilities and deferred credits in the condensed 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 and penalties under contracts. See Note 13 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. As of March 31, 2025, the insurance receivable asset related to expenses we believe are probable of recovery from property damage insurance was $425 million, recorded as offsets to the expenses incurred in other noncurrent assets in the condensed consolidated balance sheets. See Insurance Recoveries for additional information.

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. We expect the unit to return to service in late 2025 or early 2026. We estimate total cash capital expenditures required to restore the unit to service will be approximately $355 million, of which approximately $155 million in cash capital expenditures have been incurred as of September 30, 2025.

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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 nine months ended September 30, 2025, we recognized property damage insurance recoveries of $104 million, of which $24 million was recorded as an offset to operating costs incurred to restore the unit to service, and $80 million was recorded as a gain in other income, net in the condensed consolidated statements of operations. See Insurance Recoveries for additional information.

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 three and nine months ended September 30, 2025.
Three Months Ended September 30, 2025Nine Months Ended September 30, 2025
Moss Landing IncidentMartin Lake IncidentTotalMoss Landing IncidentMartin Lake IncidentTotal
(in millions)
Write-off of net book value of facility to depreciation and amortization$— $— $— $400 $— $400 
Operating costs incurred to restore Martin Lake to service— 4 4 — 24 24 
Incurred and estimated cost of ASAOC activities to operating costs (a)— — — 102 — 102 
Total incident expense$— $4 $4 $502 $24 $526 
Property damage insurance receivable as of the beginning of the period (b)$304 $20 $324 $— $— $— 
Recovery of incident expense recorded to insurance receivable — 4 4 425 24 449 
Insurance recovery gain recorded in other non-operating income, net— — — — 80 80 
Insurance proceeds received(7)(20)(27)(128)(100)(228)
Property damage insurance receivable as of the end of the period (b)$297 $4 $301 $297 $4 $301 
Total incident expense, net of property damage insurance recoveries$— $— $— $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 condensed 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 condensed consolidated balance sheets.

The following table summarizes the business interruption insurance recoveries related to the Moss Landing Incident and Martin Lake Incident during the three and nine months ended September 30, 2025.
Three Months Ended September 30, 2025Nine Months Ended September 30, 2025
Moss Landing IncidentMartin Lake IncidentTotalMoss Landing IncidentMartin Lake IncidentTotal
(in millions)
Business interruption insurance proceeds received (a)$1 $— $1 $22 $— $22 
____________
(a)Business interruption insurance proceeds is included in operating revenues in the condensed consolidated statements of operations.

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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 period ended September 30, 2025. These additional proceeds will be recorded as income in the period they are realized.

Recent Developments

Acquisition of Natural Gas Generation Facilities

In October 2025, Vistra Operations completed the acquisition of subsidiaries of Lotus Infrastructure Partners (Lotus). See Note 2 for additional information.

Debt, Credit Facilities, and Financings

Vistra Operations Commodity-Linked Revolving Credit Facility — In October 2025, Vistra Operations amended the Commodity-Linked Facility to, among other things, (i) extend the maturity date to September 30, 2026, and (ii) modify the calculation of the borrowing base. See Note 9 for additional information. In October 2025, Vistra Operations borrowed $100 million under the Commodity-Linked Facility.

Vistra Operations Senior Secured Notes — 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, $500 million aggregate principal amount of 4.600% senior secured notes due 2030, and $750 million principal amount of 5.250% senior secured notes due 2035 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. See Note 9 for additional information.

Vistra Operations Senior Unsecured Notes — In October 2025, Vistra Operations used 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.

Share Repurchase Program

In October 2025, the Board authorized an incremental amount of $1.0 billion for repurchases under our share repurchase program.

2.    ACQUISITIONS

Acquisition of Natural Gas Generation Facilities

On October 22, 2025 (Acquisition Date), pursuant to a purchase and sale agreement dated May 15, 2025, Vistra Operations acquired 100% of the membership interests of subsidiaries of Lotus (the Acquisition). The 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 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 Acquisition will be 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. Vistra will provide the amounts recognized as of the Acquisition Date for the major classes of assets acquired and liabilities assumed, as well as the supplemental pro forma revenues and net income of Vistra as if the Acquisition had been completed on January 1, 2024, in Vistra's Annual Report on Form 10‑K for the period ended December 31, 2025.

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Energy Harbor Business Combination

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023, (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (Avenue) exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively, Energy Harbor Merger). The Energy Harbor Merger combined Energy Harbor's and Vistra's nuclear and retail businesses and certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free technologies (dispatchable and renewables/storage) and the retail business.

The Energy Harbor Merger was accounted for using the acquisition method in accordance with ASC 805 which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated fair values on the Merger Date. The combined results of operations are reported in the condensed consolidated financial statements beginning as of the Merger Date.

The following table summarizes the acquisition date fair value of Energy Harbor associated with the Energy Harbor Merger on the Merger Date:
Consideration
(in millions)
Cash consideration$3,100 
15% of the fair value of net assets contributed to Vistra Vision by Vistra (a)
1,496 
Total purchase price4,596 
Fair value of noncontrolling interest in Energy Harbor (b)811 
Acquisition date fair value of Energy Harbor$5,407 
____________
(a)Valued using a discounted cash flow analysis of the contributed subsidiaries including contributed debt.
(b)Represents 15% of the acquisition date fair value implied from the fair value of consideration transferred.

As a result of the Energy Harbor Merger, Vistra maintained an 85% ownership interest in Vistra Vision and recorded the remaining 15% equity interest as a noncontrolling interest in the condensed consolidated balance sheets as of the Merger Date. On the Merger Date, we reclassified the carrying value of assets contributed to Vistra Vision of $749 million from additional paid-in-capital of Vistra (the controlling interest) to the noncontrolling interest in subsidiary.

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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:
Fair Value as of March 1, 2024
Measurement Period Adjustments
(in millions)
Cash and cash equivalents$35 $5 
Trade accounts receivables, inventories, prepaid expenses and other current assets540 2 
Investments (a)2,021 — 
Property, plant and equipment (b)5,616 (4)
Identifiable intangible assets (c)444 16 
Commodity and other derivative contractual assets (d)129 (11)
Other noncurrent assets62 54 
Total identifiable assets acquired8,847 62 
Trade accounts payable and other current liabilities318 55 
Long-term debt, including amounts due currently413 — 
Commodity and other derivative contractual liabilities (d)179 — 
Accumulated deferred income taxes1,314 (50)
Asset retirement obligations (e)1,368 — 
Identifiable intangible liabilities55 (18)
Other noncurrent liabilities and deferred credits20 8 
Total identifiable liabilities assumed3,667 (5)
Identifiable net assets acquired5,180 67 
Goodwill (f)227 (67)
Net assets acquired$5,407 
____________
(a)Investments represent securities held in nuclear decommissioning trusts (NDT) for the purpose of funding the future retirement and decommissioning of the PJM nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC. They are valued using a market approach (Level 1 or Level 2 depending on security).
(b)Acquired property, plant, and equipment are valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).
(c)Includes acquired nuclear fuel supply contracts valued based on contractual cash flow projections over approximately five years compared with cash flows based on current market prices with the resulting difference discounted to present value (Level 3). Also includes acquired retail customer relationships which are valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3).
(d)Acquired derivatives are valued using the methods described in Note 11 (Level 1, Level 2, or Level 3). Contracts with terms that were not at current market prices are also valued using a discounted cash flow analysis (Level 3).
(e)Asset retirement obligations are valued using a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies (Level 3).
(f)The excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed is recorded as goodwill. Goodwill represents expected synergies to be generated from combining operations of Energy Harbor with Vistra. None of the Goodwill is deductible for income tax purposes.

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The following unaudited pro forma financial information for the three and nine months ended September 30, 2024 assumes that the Energy Harbor Merger 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 Energy Harbor Merger 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.
Three Months Ended September 30, 2024Nine Months Ended September 30, 2024
(in millions)
Revenues$6,288 $13,911 
Net income$1,837 $2,411 

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Energy Harbor Merger, effects of the Energy Harbor Merger on tax expense (benefit), and other related adjustments. Determining the amounts of revenue and earnings of Energy Harbor since the acquisition date is impractical as operations have been integrated into our commercial platform which is managed at a portfolio level.

Acquisition costs incurred in the Energy Harbor Merger totaled $1 million and $25 million for the three and nine months ended September 30, 2024, respectively, and are classified as selling, general, and administrative expenses in the condensed 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 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, with all closing conditions met. Upon closing, we reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation. See Note 9 for additional information.

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3.    REVENUE

Revenue Disaggregation

The following tables disaggregate our revenue by major source:
Three Months Ended September 30, 2025
RetailTexasEastWestAsset
Closure		Eliminations / Corporate and OtherConsolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT$2,698 $— $— $— $— $— $2,698 
Retail energy charge in Northeast/Midwest1,054 — — — — — 1,054 
Wholesale generation revenue from ISO/RTO— 112 543 28 — — 683 
Capacity revenue from ISO/RTO (a)— — 79 — — — 79 
Revenue from other wholesale contracts— 100 101 61 — 2 264 
Total revenue from contracts with customers3,752 212 723 89 — 2 4,778 
Other revenues:
Transferable PTC revenues (b)— 145 — — — — 145 
Hedging revenues — realized396 (422)(108)26 — — (108)
Hedging revenues — unrealized(43)251 (97)50 1 — 162 
Business interruption insurance proceeds— — — — 1 — 1 
Intangible amortization and other revenues— — (7)— — — (7)
Intersegment sales (c)34 1,613 1,239 — — (2,886)— 
Total other revenues387 1,587 1,027 76 2 (2,886)193 
Total revenues$4,139 $1,799 $1,750 $165 $2 $(2,884)$4,971 
____________
(a)Includes $270 million of capacity sold offset by $191 million of capacity purchased in each ISO/RTO in the East segment. If the net capacity purchased or sold in an ISO/RTO results in a net capacity purchase, the net purchase is included in fuel, purchased power costs, and delivery fees.
(b)Represents transferable PTCs generated from qualifying nuclear and solar assets during the period.
(c)The Texas segment includes $28 million of intersegment unrealized net losses and the East segment includes $4 million of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

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Three Months Ended September 30, 2024
RetailTexasEast (a)WestAsset
Closure		Eliminations / Corporate and OtherConsolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT$2,500 $— $— $— $— $— $2,500 
Retail energy charge in Northeast/Midwest (a)1,051 — — — — — 1,051 
Wholesale generation revenue from ISO/RTO— 122 347 50 1 — 520 
Capacity revenue from ISO/RTO (b)— — 18 — — — 18 
Revenue from other wholesale contracts— 93 100 48 10 1 252 
Total revenue from contracts with customers3,551 215 465 98 11 1 4,341 
Other revenues:
Transferable PTC revenue— 4 — — — — 4 
Hedging revenues — realized373 (382)(52)35 (3)— (29)
Hedging revenues — unrealized308 1,253 299 98 2 — 1,960 
Intangible amortization and other revenues1 — (1)— 1 11 12 
Intersegment sales (c)18 3,154 1,142 1 — (4,315)— 
Total other revenues700 4,029 1,388 134 — (4,304)1,947 
Total revenues$4,251 $4,244 $1,853 $232 $11 $(4,303)$6,288 
____________
(a)Includes revenues associated with operations acquired in the Energy Harbor Merger.
(b)Represents net capacity sold in each ISO/RTO. The East segment includes $30 million of capacity sold offset by $12 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in the condensed consolidated statement of operations includes capacity purchased of $44 million offset by $28 million of capacity sold within the East segment.
(c)The Texas, East, and West segment includes $1.527 billion, $55 million, and $1 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

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Nine Months Ended September 30, 2025
RetailTexasEastWestAsset
Closure		Eliminations / Corporate and OtherConsolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT$6,890 $— $— $— $— $— $6,890 
Retail energy charge in Northeast/Midwest2,886 — — — — — 2,886 
Wholesale generation revenue from ISO/RTO— 231 1,725 75 — — 2,031 
Capacity revenue from ISO/RTO (a)— — 129 — — — 129 
Revenue from other wholesale contracts— 338 323 176 5 3 845 
Total revenue from contracts with customers9,776 569 2,177 251 5 3 12,781 
Other revenues:
Transferable PTC revenues (b)— 151 — — — — 151 
Hedging revenues — realized1,040 (458)(158)90 — — 514 
Hedging revenues — unrealized(59)198 (446)4 2 — (301)
Business interruption insurance proceeds— — — — 22 — 22 
Intangible amortization and other revenues— (2)(11)— — — (13)
Intersegment sales (c)82 3,339 3,048 2 (3)(6,468)— 
Total other revenues1,063 3,228 2,433 96 21 (6,468)373 
Total revenues$10,839 $3,797 $4,610 $347 $26 $(6,465)$13,154 
____________
(a)Includes $477 million of capacity sold offset by $348 million of capacity purchased in each ISO/RTO in the East segment. If the net capacity purchased or sold in an ISO/RTO results in a net capacity purchase, the net purchase is included in fuel, purchased power costs, and delivery fees.
(b)Represents transferable PTCs generated from qualifying nuclear and solar assets during the period.
(c)The Texas and East segments include $93 million and $103 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Nine Months Ended September 30, 2024
RetailTexasEast (a)WestAsset
Closure		Eliminations / Corporate and OtherConsolidated
(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT$6,241 $— $— $— $— $— $6,241 
Retail energy charge in Northeast/Midwest (a)2,705 — — — — — 2,705 
Wholesale generation revenue from ISO/RTO— 278 844 164 4 — 1,290 
Capacity revenue from ISO/RTO (b)— — 54 — — — 54 
Revenue from other wholesale contracts— 325 312 147 24 1 809 
Total revenue from contracts with customers8,946 603 1,210 311 28 1 11,099 
Other revenues:
Transferable PTC revenues— 9 — — — — 9 
Hedging revenues — realized927 (524)35 68 (8)— 498 
Hedging revenues — unrealized(3)893 356 317 8 — 1,571 
Intangible amortization and other revenues— — (3)— 1 12 10 
Intersegment sales (c)43 3,943 2,643 5 — (6,634)— 
Total other revenues967 4,321 3,031 390 1 (6,622)2,088 
Total revenues$9,913 $4,924 $4,241 $701 $29 $(6,621)$13,187 
____________
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(a)Includes seven months of revenue associated with operations acquired in the Energy Harbor Merger.
(b)Represents net capacity sold in each ISO/RTO. The East segment includes $94 million of capacity sold offset by $40 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the condensed consolidated statement of operations includes capacity purchased of $88 million offset by $47 million of capacity sold within the East segment.
(c)The Texas and West segments include $605 million and $3 million, respectively, of intersegment unrealized net gains and the East segment includes $123 million of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Performance Obligations

As of September 30, 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 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.
Balance of 2025
2026202720282029
2030 and Thereafter
Total
(in millions)
Remaining performance obligations$370 $1,647 $882 $122 $62 $548 $3,631 

Trade Accounts Receivable
September 30, 2025December 31,
2024
(in millions)
Wholesale and retail trade accounts receivable$2,431 $2,061 
Allowance for credit losses(104)(79)
Trade accounts receivable — net$2,327 $1,982 
Trade accounts receivable from contracts with customers — net$1,776 $1,514 
Other trade accounts receivable — net551 468 
Trade accounts receivable — net$2,327 $1,982 

Gross trade accounts receivable as of September 30, 2025 and December 31, 2024 include unbilled retail revenues of $924 million and $802 million, respectively.

Allowance for Credit Losses on Accounts Receivable
Nine Months Ended September 30,
20252024
(in millions)
Allowance for credit losses on accounts receivable at beginning of period$79 $61 
Increase for bad debt expense152 132 
Decrease for account write-offs(127)(105)
Allowance for credit losses on accounts receivable at end of period$104 $88 

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4.    GOVERNMENT ASSISTANCE

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S. 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 the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance.

Transferable PTCs

In each of the three and nine months ended September 30, 2025, we recognized transferable nuclear PTC revenues of $145 million. Nuclear PTC revenues are an estimate based on projected annual gross receipts generated from qualifying nuclear production in 2025 and reflect our determination that we will meet the prevailing wage requirements necessary to earn the five times multiplier. The amount recognized in the nine months ended September 30, 2025 reflects a pro-rata allocation of the forecasted annual nuclear PTC revenue based on actual qualifying nuclear production during the period. Our computation of forecasted gross receipts includes merchant energy revenues and capacity revenues (for our PJM nuclear units only) at each nuclear unit and excludes any hedges and ancillary 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 2024 and 2025 and would be reflected as a change in estimate in the period in which the guidance is received.

Sales of Transferable PTCs

During 2025, we sold $490 million 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 $278 million and $469 million were received during the three and nine months ended September 30, 2025, respectively.

5.    INCOME TAXES

Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra serves as the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.

Income Tax Expense

The components of our income tax expense are as follows:
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions)
Net income before income taxes$856 $2,392 $815 $3,016 
Income tax expense$(204)$(555)$(104)$(694)
Effective tax rate23.8 %23.2 %12.8 %23.0 %

We evaluate and update our annual effective income tax rate on an interim basis based on current and forecasted earnings and tax laws. The mix and timing of our actual earnings compared to annual projections, as well as the amount of pre-tax earnings in comparison to the required discrete items, can cause interim effective tax rate fluctuations.

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For the three months ended September 30, 2025, the effective rate of 23.8% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes. For the nine months ended September 30, 2025, the effective tax rate of 12.8% was lower than the U.S. federal statutory rate of 21% due primarily to permanent differences recorded discretely related to stock-based compensation, partially offset by state income taxes.

For the three months ended September 30, 2024, the effective tax rate of 23.2% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes. For the nine months ended September 30, 2024, the effective tax rate of 23.0% was higher than the U.S. federal statutory rate of 21% due primarily to the impact of state income taxes offset by discrete tax benefits related to stock-based compensation.

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 consolidated financial statements. 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.

6.    PROPERTY, PLANT, AND EQUIPMENT

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. Land and construction work in progress are not depreciated.
September 30, 2025December 31,
2024
(in millions)
Power generation and structures and office and other equipment$22,510 $22,943 
Land614 603 
Construction work in progress (a)1,969 1,060 
Finance lease right-of-use assets186 186 
Nuclear fuel2,054 1,843 
Property, plant and equipment — gross27,333 26,635 
Less accumulated depreciation(8,918)(8,020)
Less finance lease right-of-use assets accumulated amortization(39)(33)
Less accumulated amortization on nuclear fuel(651)(409)
Property, plant and equipment — net$17,725 $18,173 
____________
(a)During the three and nine months ended September 30, 2025, we recognized impairments of $5 million and $73 million, respectively, related to development projects we have no plans to complete.

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Depreciation and amortization of property, plant, and equipment (including the classification in the condensed consolidated statements of operations) consisted of the following:
Property, Plant, and EquipmentCondensed Consolidated Statements of OperationsThree Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions)
Power generation and structures and office and other equipmentDepreciation and amortization$417 $419 $1,393 $1,173 
Finance lease right-of-use assetsDepreciation and amortization2 2 6 6 
Nuclear fuelFuel, purchased power costs, and delivery fees129 123 366 269 
Total property, plant, and equipment expense$548 $544 $1,765 $1,448 

Retirement of Generation Facilities

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 or is expected to occur. The Moss Landing 300 facility was transferred to the Asset Closure segment during the first quarter of 2025 as we do not plan to return the asset to operations. See Note 1 for additional information.
FacilityLocationISO/RTOFuel TypeNet Capacity (MW)Expected or Actual Retirement Date (a)Segment
BaldwinBaldwin, ILMISOCoal1,185By the end of 2027East
Coleto CreekGoliad, TXERCOTCoal650By the end of 2027Texas
KincaidKincaid, ILPJMCoal1,108By the end of 2027East
Miami FortNorth Bend, OHPJMCoal1,020By the middle of 2028East
NewtonNewton, ILMISOCoal615By the end of 2027East
Total4,578
____________
(a)Expected retirement dates may 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.

7.    GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

As of September 30, 2025 and December 31, 2024, the carrying value of goodwill totaled $2.810 billion and $2.807 billion, respectively.
Retail SegmentTexas Segment
Retail Reporting Unit (a)Texas Reporting UnitGoodwill Pending AllocationTotal Goodwill
(in millions)
Balance at December 31, 2024
$2,461 $122 $224 $2,807 
Measurement period adjustment recorded in connection with the Energy Harbor Merger (b)227 — (224)3 
Balance at September 30, 2025
$2,688 $122 $— $2,810 
____________
(a)Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight line basis.
(b)Includes the allocation of goodwill attributable to the Energy Harbor acquisition to the retail reporting unit (see Note 2 for additional information).

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Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:
September 30, 2025December 31, 2024
Identifiable Intangible Asset
Gross
Carrying
Amount
Accumulated
Amortization		Net
Gross
Carrying
Amount
Accumulated
Amortization		Net
(in millions)
Retail customer relationships$2,173 $2,044 $129 $2,173 $1,977 $196 
Software and other technology-related assets566 347 219 601 293 308 
Retail and wholesale contracts503 410 93 503 353 150 
Long-term service agreements18 6 12 18 5 13 
Other identifiable intangible assets (a)319 16 303 218 13 205 
Total identifiable intangible assets subject to amortization$3,579 $2,823 756 $3,513 $2,641 872 
Retail trade names (not subject to amortization)1,341 1,341 
Total identifiable intangible assets$2,097 $2,213 
____________
(a)Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).

Identifiable intangible liabilities are comprised of the following:
Identifiable Intangible LiabilitySeptember 30, 2025December 31, 2024
(in millions)
Long-term service agreements$101 $108 
Wholesale power and fuel purchase contracts40 47 
Total identifiable intangible liabilities$141 $155 

Amortization of finite-lived identifiable intangible assets and liabilities (including the classification in the condensed consolidated statements of operations) consisted of the following:
Identifiable Intangible Assets/LiabilitiesCondensed Consolidated Statements of OperationsThree Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions)
Retail customer relationshipsDepreciation and amortization$23 $29 $68 $82 
Software and other technology-related assetsDepreciation and amortization17 15 53 43 
Retail and wholesale contractsOperating revenues/Fuel, purchased power costs, and delivery fees(2)(5)(6)(9)
Other identifiable intangible assets (a)Fuel, purchased power costs, and delivery fees/Depreciation and amortization127 131 350 327 
Total intangible asset expense, net$165 $170 $465 $443 
___________
(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 condensed consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.

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Estimated Amortization of Identifiable Intangible Assets

As of September 30, 2025, the estimated aggregate amortization expense of identifiable intangible assets, excluding environmental allowances, for each of the next five fiscal years is as shown below.
YearEstimated Amortization Expense
(in millions)
2025$218 
2026$168 
2027$73 
2028$53 
2029$37 

8.    COLLATERAL FINANCING AGREEMENT WITH AFFILIATE

In 2023, Vistra Operations entered into a facility agreement with a Delaware trust formed by the Company (the Trust) that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $450 million. The Trust is not consolidated by Vistra. The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S. Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S. dollars, the Eligible Assets). At the direction of Vistra Operations, the Eligible Assets held by the Trust can be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program.

As of September 30, 2025 and December 31, 2024, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $450 million and $435 million, respectively, and is reported in the condensed consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate. See Note 8 to the Financial Statements in our 2024 Form 10-K for additional information.

9.    DEBT, CREDIT FACILITIES, AND FINANCINGS

Debt, credit facilities and financing obligations on the condensed consolidated balance sheets consisted of the following:
September 30, 2025December 31, 2024
(in millions)
Long-term debt, including amounts due currently:
Project-level debt$1,488 $1,064 
Vistra Operations debt14,642 15,405 
Long -term debt before unamortized premiums, discounts and issuance costs16,130 16,469 
Unamortized premiums, discounts and issuance costs(142)(171)
Long-term debt including amounts due currently$15,988 $16,298 
Accounts receivable financing$1,225 $750 
Forward repurchase obligation$1,314 $1,335 

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Long-Term Debt

The Company's long-term debt obligations, including amounts due currently, consisted of the following:
September 30, 2025December 31, 2024
(in millions)
Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030$2,456 $2,475 
BCOP Credit Facility, Bridge Loans (a)367 367 
BCOP Credit Facility, Construction / Term Loans (a)424 — 
Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031697 697 
Vistra Operations Senior Secured Notes:
5.125% Senior Secured Notes, due May 13, 2025
— 744 
5.050% Senior Secured Notes, due December 30, 2026
500 500 
3.700% Senior Secured Notes, due January 30, 2027
800 800 
4.300% Senior Secured Notes, due July 15, 2029
800 800 
6.950% Senior Secured Notes, due October 15, 2033
1,050 1,050 
6.000% Senior Secured Notes, due April 15, 2034
500 500 
5.700% Senior Secured Notes, due December 30, 2034
750 750 
Total Vistra Operations Senior Secured Notes4,400 5,144 
Energy Harbor Revenue Bonds:
3.375% Revenue Bond, due August 1, 2029
100 100 
4.750% Revenue Bonds, due June 1, 2033 and July 1, 2033
285 285 
3.750% Revenue Bond, due October 1, 2047
46 46 
Total Energy Harbor Revenue Bonds431 431 
Vistra Operations Senior Unsecured Notes:
5.500% Senior Unsecured Notes, due September 1, 2026
1,000 1,000 
5.625% Senior Unsecured Notes, due February 15, 2027
1,300 1,300 
5.000% Senior Unsecured Notes, due July 31, 2027
1,300 1,300 
4.375% Senior Unsecured Notes, due May 1, 2029
1,250 1,250 
7.750% Senior Unsecured Notes, due October 15, 2031
1,450 1,450 
6.875% Senior Unsecured Notes, due April 15, 2032
1,000 1,000 
Total Vistra Operations Senior Unsecured Notes7,300 7,300 
Other:
Equipment Financing Agreements55 55 
Total other long-term debt55 55 
Unamortized debt premiums, discounts and issuance costs(142)(171)
Total long-term debt including amounts due currently15,988 16,298 
Less amounts due currently (b)
(231)(880)
Total long-term debt less amounts due currently$15,757 $15,418 
___________
(a)See Credit Facilities table below for details of the BCOP Credit Facility maturities.
(b)Excludes 5.500% Senior Unsecured Notes due September 1, 2026 as amounts were refinanced on a long-term basis using a portion of the net proceeds from the October 2025 issuance of $2.0 billion of Vistra Operations senior secured notes. See Vistra Operations Senior Secured Notes below.

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Long-Term Debt Maturities

Long-term debt maturities as of September 30, 2025 are as follows:
September 30, 2025
(in millions)
Remainder of 2025$208 
2026 (a)2,014 
20273,432 
202832 
20292,283 
Thereafter8,161 
Unamortized premiums, discounts and debt issuance costs(142)
Total long-term debt, including amounts due currently$15,988 
___________
(a)Includes 5.500% Senior Unsecured Notes due September 1, 2026 that were refinanced on a long-term basis using a portion of the net proceeds from the October 2025 issuance of $2.0 billion of Vistra Operations senior secured notes. See Vistra Operations Senior Secured Notes below.

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Credit Facilities

Our credit facilities and related available capacity as of September 30, 2025 are presented below.
September 30, 2025
Credit FacilitiesMaturity DateFacility
Limit		Cash
Borrowings (Long-Term Debt, Including Amounts Due Currently)		Letters of
Credit Outstanding		Available
Capacity
(in millions)
Vistra Operations debt:
Revolving Credit FacilityOctober 11, 2029$3,440 $— $981 $2,459 
Term Loan B-3 FacilityDecember 20, 20302,456 2,456 — — 
Total Vistra Operations Credit Facilities5,896 2,456 981 2,459 
Vistra Operations Commodity-Linked Facility
October 1, 2025 (a)
1,750 — — 644 
Total Vistra Operations debt$7,646 $2,456 $981 $3,103 
Project-level debt:
Bridge Loans
November 1, 2025 (b) / December 3, 2026
$367 $367 $— $— 
Construction / Term Loans
(c)
424 424 — — 
BCOP Credit Facility (d)
791 791 — — 
Vistra Zero Term Loan B Facility (d)
April 30, 2031697 697 — — 
Total project-level debt$1,488 $1,488 $— $— 
Total credit facilities$9,134 $3,944 $981 $3,103 
___________
(a)In October 2025, Vistra Operations amended the Commodity-Linked Facility to, among other things, extend the maturity date to September 30, 2026.
(b)In October 2025, the maturity date on $106 million of Bridge Loans was extended to January 30, 2026. See further discussion in BCOP Project-level Credit Facilities discussion below.
(c)Consists of $120 million of Term Loans due December 3, 2029, $88 million of Construction Term Loans with a maturity date of November 1, 2025 that converted to Term Loans on October 30, 2025 with a maturity date of December 3, 2029, and $216 million of Construction Loans with a maturity date of December 3, 2026 that are expected to convert to Term Loans on or before December 3, 2026. See further discussion in BCOP Project-level Credit Facilities discussion below.
(d)Vistra Zero Operating's and BCOP's obligations under the Vistra Zero Credit Agreement and the BCOP Credit Agreement, respectively, are guaranteed by subsidiaries of Vistra Zero Operating and BCOP, respectively, but are otherwise non-recourse to Vistra Operations and its other subsidiaries.

Vistra Operations Credit Facilities

As of September 30, 2025, the Vistra Operations Credit Facilities have aggregate commitments of up to $5.896 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 $2.456 billion (Term Loan B-3 Facility).

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Revolving Credit Facility — The Revolving Credit Facility is used for general corporate purposes. Under the Vistra Operations Credit Agreement, (i) 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 ranges from 1.25% to 2.00%, and (ii) the fee payable on any undrawn amounts with respect to the Revolving Credit Facility that ranges from 17.5 basis points to 35.0 basis points. Interest periods for Term SOFR borrowings are for 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 is paid quarterly in arrears. Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of September 30, 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 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 1.75%, and the weighted average interest rates before taking into consideration interest rate swaps (see Note 10 for additional information) on outstanding borrowings of $2.456 billion was 5.91% as of September 30, 2025. Interest periods for Term SOFR loans are for one-, three-, or six-month periods with interest paid in arrears. Cash borrowings under the Term Loan B-3 Facility are subject to required scheduled quarterly payments of $6.25 million. Amounts paid cannot be reborrowed.

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 (or, during a collateral suspension period, a consolidated total net leverage ratio). Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the existence of material unpaid (or unstayed) judgments against Vistra Operations and certain of its subsidiaries. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

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The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of September 30, 2025, Vistra Operations can distribute approximately $10.9 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 $350 million and $515 million for the three months ended September 30, 2025 and 2024, respectively, and $1.275 billion and $1.505 billion for the nine months ended September 30, 2025 and 2024, 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 September 30, 2025, all of the restricted net assets of Vistra Operations may be distributed to Parent.

Vistra Operations Commodity-Linked Revolving Credit Facility

As of September 30, 2025, the Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) totaled $1.750 billion of aggregate available commitments. We have the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility to $3.0 billion. In October 2025, Vistra Operations amended the Commodity-Linked Facility to, among other things, extend the maturity date to September 30, 2026. As of September 30, 2025, the borrowing base of $644 million is lower than the facility limit which represents the aggregate commitments of $1.750 billion.

Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero. Vistra Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce outstanding borrowings to be less than or equal to the borrowing base. Vistra Operations intends to use any borrowings provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time to time and for other working capital and general corporate purposes.

Interest on the Commodity-Linked Facility bears interest 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. Interest periods for Term SOFR borrowings are for one-, three-, or six-month periods with interest paid in arrears. The interest period for a daily simple SOFR is for a one-week period with interest paid in arrears. The fee on any undrawn amounts with respect to the Commodity-Linked Facility ranges from 17.5 basis points to 35.0 basis points. As of September 30, 2025, the applicable interest rate margins for borrowings outstanding under the Commodity-Linked Facility was 1.725% and the fee on any undrawn amounts with respect to the Commodity-Linked Facility was 27.0 basis points. Interest and fees on the Commodity-Linked Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of September 30, 2025, there were no outstanding borrowings under the Commodity-Linked Facility.

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

As of September 30, 2025, the Bridge Loans for Oak Hill and Pulaski totaled $106 million and $261 million, respectively, and will mature in November 2025 and December 2026, respectively, subject to the terms of the BCOP Credit Agreement. In October 2025, the maturity date on $106 million of Oak Hill Bridge Loans was extended to January 30, 2026. Interest is paid on the Bridge Loans in arrears based on the applicable Term SOFR elected in the borrowing notice plus a fixed spread of 1.625% per annum, and the weighted average interest rate on outstanding borrowings was 5.648% as of September 30, 2025. Repayment of the Bridge Loans is guaranteed by Vistra as the beneficiary of the underlying investment tax credits to be generated by the projects.

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The Construction/Term Loan Facility consists of (i) term loans supporting the Baldwin and Coffeen projects and (ii) construction loans to fund the Oak Hill and Pulaski project costs during construction that will convert to term loans once each project reaches its commercial operation date and term conversion date. On April 1, 2025, BCOP funded $75 million and $46 million of term loans for Baldwin and Coffeen, respectively, that will mature in December 2029, and issued $7 million in letters of credit under the Debt Service Reserve facility to support the Baldwin and Coffeen term loans. On May 20, 2025, BCOP funded $88 million of construction loans for Oak Hill with a maturity date in November 2025 and, subject to meeting certain conditions, will convert to a term loan maturing in December 2029. In October 2025, the $88 million of construction loans converted to a term loan. In July and August 2025, BCOP funded $216 million total of construction loans for Pulaski that will mature in December 2026 and, subject to meeting certain conditions, will convert to a term loan maturing in December 2029. Interest on the construction/term loans will be paid in arrears based on the applicable Term SOFR elected in the borrowing notice plus fixed spreads of 1.875% per annum for construction loans and 2.000% per annum for term loans, and the weighted average interest rate on outstanding construction/term loans was 6.03% as of September 30, 2025. Beginning on the term funding or term conversion date, the term loans will amortize over a 20-year period and debt amortization and interest payments will be funded with cash flows from the underlying project. Fees on the issued debt service reserve letters of credit will be paid in arrears at 2.000% per annum. Commitment fees on the undrawn loan commitments and unissued letter of credit commitments will be paid quarterly in arrears at a fixed percentage of the loan's fixed spread.

Vistra Zero Project-level Credit Agreement

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 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 6.16% as of September 30, 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.

Letter of Credit Facilities

Vistra Operations Secured Letter of Credit Facilities

Between August 2020 and June 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 do not have stated expiration dates and are used for general corporate purposes. As of September 30, 2025, $1.301 billion of letters of credit were outstanding under the Secured LOC Facilities.

Vistra Operations Unsecured Alternative Letter of Credit Facilities

In March 2024, we entered into unsecured alternative letter of credit facilities (Alternative LOC Facilities) to be used for general corporate purposes. In May 2024, the Alternative LOC Facilities were amended to increase the commitment cap to a total of $500 million. As of September 30, 2025, the total capacity was $500 million and $500 million of letters of credit were outstanding under the Alternative LOC Facilities. In October 2025, the Alternative LOC Facilities were amended to increase the commitment cap to a total of $800 million. The commitments under the Alternative LOC Facilities terminate in December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities.

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Vistra Operations Senior Secured Notes

Vistra Operations issues and sells its senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Secured Notes). The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the Senior Secured Notes provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities. 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 May 2025, the $744 million outstanding principal amount of the 5.125% Senior Secured Notes due May 2025 were repaid at maturity.

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 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 of each year, beginning April 15, 2026. Net proceeds from the offering, together with cash on hand, were used (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 Acquisition (see Note 2 for additional information), and (iii) to pay fees and expenses related to the offering.

Energy Harbor Revenue Bonds

Various governmental entities in Ohio and Pennsylvania have issued multiple tranches of revenue bonds for the benefit of Energy Harbor Generation LLC (EHG) or Energy Harbor Nuclear Generation LLC (EHNG); (collectively, the EH entities), in an aggregate principal amount of $431 million. The relevant EH entity is obligated to provide contractual payments to the applicable issuer of the revenue bonds to service the principal and interest on the revenue bonds, the payment of which is indirectly secured by all or substantially all of the assets of the EH entities under various mortgage bonds issued by the EH entities. In the event of a default by the EH entities of their contractual obligation to pay principal and interest in respect of the revenue bonds, the trustee of the revenue bonds would be able to call the mortgage bonds due and, if unpaid, foreclose on the assets securing the mortgage bonds. The obligations of the EH entities in respect of the revenue bonds and related mortgage bonds are guaranteed on an unsecured basis by Energy Harbor and Vistra.

Vistra Operations Senior Unsecured Notes

Vistra Operations issues and sells its senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Unsecured Notes). The indentures (as may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) governing the Senior Unsecured Notes provide for the full and unconditional guarantee by the Guarantor Subsidiaries. The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

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.

Accounts Receivable Financing

Accounts Receivable Securitization Program

TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). 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 extend the term of the Receivables Facility to July 2026.

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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 condensed consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in the condensed consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable.

As of September 30, 2025, outstanding borrowings under the Receivables Facility totaled $1.1 billion and were supported by $1.764 billion of RecCo gross receivables. As of December 31, 2024, there were $750 million outstanding borrowings under the Receivables Facility.

Repurchase Facility

TXU Energy and the other Originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 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 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). Each Repo Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.

TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the Receivables Facility.

As of September 30, 2025, outstanding borrowings under the Repurchase Facility totaled $125 million. There were no outstanding borrowings under the Repurchase Facility as of December 31, 2024.

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Forward Repurchase Obligation

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. In June 2025, Vistra made scheduled installment payments to reduce the forward repurchase obligation by $80 million, including $41 million of principal and $39 million of interest. Principal and interest payments remaining due to Nuveen are as follows:
September 30, 2025
(in millions)
Remainder of 2025$701 
2026669 
Thereafter— 
Total scheduled payments under the UPAs$1,370 

The present value of the remaining payment obligations to Nuveen discounted at 6% totaled $1.314 billion and $1.335 billion at September 30, 2025 and December 31, 2024, respectively, and is included in forward repurchase obligation due currently and forward obligation, less amounts due currently in the condensed consolidated balance sheet.

Interest Expense and Related Charges
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions)
Interest expense$272 $244 $819 $702 
Unrealized mark-to-market net losses on interest rate swaps10 84 84 26 
Amortization of debt issuance costs, discounts, and premiums11 9 33 25 
Debt extinguishment gain— — — (6)
Capitalized interest(30)(20)(86)(52)
Other23 15 58 48 
Total interest expense and related charges$286 $332 $908 $743 

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 5.21% and 5.52% as of September 30, 2025 and 2024, respectively.

10.    DERIVATIVES

We utilize derivative instruments, such as options, swaps, futures and forward contracts, to manage our exposure to commodity price and interest rate volatility. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, fuel oil and natural gas producers, local distribution companies, and energy marketing companies.

Commodity Derivatives

We utilize financial natural gas and financial and physical electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets. Financial transmission rights and congestion revenue rights are derivative instruments we utilize to hedge electricity price differences between settlement points within regions. Gains and losses associated with these derivatives are reported in the condensed consolidated statements of operations in operating revenues.

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We utilize physical natural gas, coal, emissions, and renewable energy certificate derivatives primarily to hedge future purchased power costs of our retail operations or fuel costs of our generation assets. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in fuel, purchased power costs, and delivery fees.

Our Retail segment procures power from our generation segments to serve future load obligations. In locations and periods where our load service activities do not naturally offset existing generation portfolio risks, remaining commodity price exposure is managed through portfolio hedging activities.

Interest Rate Swaps

Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Gains and losses associated with these derivatives are reported in the condensed consolidated statements of operations in interest expense and related charges.

As of September 30, 2025, Vistra has entered into the following interest rate swaps:
Notional AmountExpiration Date
Rate Range (d)
(in millions, except percentages)
Swapped to fixed (a)$3,000July 20262.89 %-2.97%
Swapped to variable (a)$700July 20261.44 %-1.49%
Swapped to fixed (b)$2,300December 20303.20 %-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. These matched swaps will settle over time and effectively offset the hedged position. These offsetting swaps expiring in July 2026 hedge our exposure on $2.3 billion of variable rate debt through July 2026.
(b)Effective from July 2026 through December 2030. 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 9 for additional information).
(d)The rate ranges reflect the fixed leg of each swap at the applicable Term SOFR rate.

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheets

We maintain standardized master netting agreements with certain counterparties that allow for the right to offset accounts payable, accounts receivable, and cash collateral paid in order to reduce credit exposure. The following tables reconcile our gross derivative assets and liabilities as reported in the condensed consolidated balance sheets to the net value on a contract basis, after taking into consideration netting arrangements with counterparties and cash collateral recorded.

September 30, 2025
Derivative Contract AssetsDerivative Contract Liabilities
Commodity ContractsInterest Rate SwapsCommodity ContractsInterest Rate SwapsTotal
(in millions)
Current assets$2,615 $18 $1 $— $2,634 
Noncurrent assets579 2 23 — 604 
Current liabilities— — (3,596)(14)(3,610)
Noncurrent liabilities(4)— (1,362)(22)(1,388)
Net assets (liabilities)$3,190 $20 $(4,934)$(36)$(1,760)
Offsetting instruments (a)(2,553)(12)2,553 12 — 
Financial collateral (received) pledged (b)(11)— 516 — 505 
Net amounts$626 $8 $(1,865)$(24)$(1,255)
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December 31, 2024
Derivative Contract AssetsDerivative Contract Liabilities
Commodity ContractsInterest Rate SwapsCommodity ContractsInterest Rate SwapsTotal
(in millions)
Current assets$2,551 $34 $2 $— $2,587 
Noncurrent assets677 62 1 — 740 
Current liabilities— — (3,333)(18)(3,351)
Noncurrent liabilities(2)— (1,356)(9)(1,367)
Net assets (liabilities)$3,226 $96 $(4,686)$(27)$(1,391)
Offsetting instruments (a)(2,532)(28)2,532 28 — 
Financial collateral (received) pledged (b)(50)— 233 — 183 
Net amounts$644 $68 $(1,921)$1 $(1,208)
____________
(a)Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
(b)Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements.

Effect of Derivative Instruments in the Condensed Consolidated Statements of Operations

The following table summarizes the location and amount of unrealized gains and losses from our derivative instruments recorded in the condensed consolidated statements of operations for the three and nine months ended September 30, 2025 and 2024:
Derivative (condensed consolidated statements of operations presentation)Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions)
Reversals of previously recognized unrealized (gain) loss on derivative instruments:
Commodity contracts unrealized (gain) loss in operating revenues (a)$735 $754 $878 $1,172 
Commodity contracts unrealized (gain) loss in fuel, purchased power costs, and delivery fees (a)11 23 3 178 
Interest rate swaps unrealized (gain) loss in interest expense and related charges(5)(11)(16)(33)
Total reversals of previously recognized unrealized (gain) loss on derivative instruments$741 $766 $865 $1,317 
Unrealized net gain (loss) from changes in fair value on derivative instruments:
Commodity contracts unrealized gain (loss) in operating revenues$(573)$1,206 $(1,179)$399 
Commodity contracts unrealized gain (loss) in fuel, purchased power costs, and delivery fees11 (128)(69)(24)
Interest rate swaps unrealized gain (loss) in interest expense and related charges(5)(73)(68)7 
Total unrealized net gain (loss) from change in fair value on derivative instruments$(567)$1,005 $(1,316)$382 
Net gain (loss) on derivative instruments$174 $1,771 $(451)$1,699 
____________
(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.

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Derivative Volumes

The following table presents the gross notional amounts of derivative volumes by commodity, excluding our normal purchases and normal sales (NPNS) derivatives that are not recorded at fair value:
September 30, 2025December 31, 2024
Derivative typeNotional VolumeUnit of Measure
Natural gas4,017 4,568 Million MMBtu
Electricity881,426 796,982 GWh
Financial transmission rights / Congestion revenue rights254,680 248,742 GWh
Coal29 27 Million U.S. tons
Fuel oil3 2 Million gallons
Emissions33 28 Million U.S. tons
Renewable energy certificates29 31 Million certificates
Interest rate swaps – variable/fixed$5,716 $5,300 Million U.S. dollars
Interest rate swaps – fixed/variable$700 $700 Million U.S. dollars

Credit Risk-Related Contingent Features of Derivatives

Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements may require the posting of additional collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:
September 30, 2025December 31,
2024
(in millions)
Fair value of derivative contract liabilities (a)$(1,432)$(1,587)
Offsetting fair value under netting arrangements (b)597 724 
Cash collateral and letters of credit293 471 
Liquidity exposure$(542)$(392)
____________
(a)Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).
(b)Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.

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Concentrations of Credit Risk Related to Derivatives

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) 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.
September 30, 2025
(in millions, except percentages)
Credit risk exposure to derivative contract counterparties:
Gross exposure$3,653 
Net exposure (a)$740 
Largest net exposure from any single counterparty (a)$302 
Percent of credit risk exposure to derivative contract counterparties related to banking and financial sector:
Gross exposure73 %
Net exposure (a)13 %
____________
(a)Exposure after taking into effect netting arrangements, setoff provisions, and collateral.

11.    FAIR VALUE MEASUREMENTS

Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own market assumptions. We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy as defined by GAAP:

•Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date.
•Level 2 valuations use over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals.
•Level 3 valuations use unobservable inputs for the asset or liability, typically reflecting our estimate of assumptions that market participants would use in pricing the asset or liability. The fair value is therefore determined using model-based techniques, including discounted cash flow models.

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

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
September 30, 2025December 31, 2024
Level
1		Level
2		Level
3		Reclass
(a)		TotalLevel
1		Level
2		Level
3		Reclass
(a)		Total
(in millions)
Assets:
Commodity contracts (b)$2,047 $416 $727 $28 $3,218 $1,923 $462 $841 $5 $3,231 
Interest rate swaps (b)— 20 — — 20 — 96 — — 96 
NDTs – equity securities (c)(d)1,769 — — 1,769 1,560 — — 1,560 
NDTs – debt securities (c)(e)110 1,877 — 1,987 83 1,976 — 2,059 
Sub-total$3,926 $2,313 $727 $28 6,994 $3,566 $2,534 $841 $5 6,946 
Assets measured at net asset value (f):
NDTs – equity securities (c)(d)(f)850 821 
NDTs - debt securities (c)(e)(f)323 — 
Total assets$8,167 $7,767 
Liabilities:
Commodity contracts (b)$2,574 $686 $1,674 $28 $4,962 $2,118 $975 $1,593 $5 $4,691 
Interest rate swaps (b)— 36 — — 36 — 27 — — 27 
Total liabilities$2,574 $722 $1,674 $28 $4,998 $2,118 $1,002 $1,593 $5 $4,718 
___________
(a)Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability position. This reclassification represents the adjustment needed to reconcile to the gross amounts presented in the condensed consolidated balance sheets.
(b)See Note 10 for additional information.
(c)NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in Investments in the condensed 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 September 30, 2025.
(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.
(e)The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt securities are weighted with government and investment grade corporate bonds. Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 4.14% and 3.99% as of September 30, 2025 and December 31, 2024, respectively, and an average maturity of eight years and seven years as of September 30, 2025 and December 31, 2024, respectively. NDT debt securities held as of September 30, 2025 mature as follows: $783 million in one to five years, $1.074 billion in five to 10 years and $453 million after 10 years.
(f)Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair values and therefore are not classified in the fair value hierarchy. This amount is presented to permit reconciliation of this table to the amounts presented in the condensed consolidated balance sheets.

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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 September 30, 2025 and December 31, 2024:
September 30, 2025
Fair Value
Contract Type (a)AssetsLiabilitiesTotal, NetValuation TechniqueSignificant Unobservable InputRange (b)Average (b)
(in millions)
Electricity purchases and sales$467 $(1,457)$(990)Income ApproachHourly price curve shape (c)$—to$95$48
MWh
Illiquid delivery periods for hub power prices (d)$25to$135$80
MWh
Market Heat Rates (d)$25to$135$80
MWh
Options3 (173)(170)Option Pricing ModelNatural gas to power correlation (e)15%to100%58%
Power and natural gas volatility (e)5%to970%488%
Financial transmission rights/Congestion revenue rights231 (33)198 Market Approach (f)Illiquid price differences between settlement points (g)$(12)to$25$6.5
MWh
Natural gas16 (11)5 Income ApproachNatural gas basis (h)$(1)to$14$6
MMBtu
Illiquid delivery periods (i)$3to$5$4
MMBtu
Other (j)10 — 10 
Total$727 $(1,674)$(947)
December 31, 2024
Fair Value
Contract Type (a)AssetsLiabilitiesTotal,
Net		Valuation TechniqueSignificant Unobservable InputRange (b)Average (b)
(in millions)
Electricity purchases and sales$606 $(1,399)$(793)Income ApproachHourly price curve shape (c)$—to$95$48
MWh
Illiquid delivery periods for hub power prices (d)$25to$140$83
MWh
Market Heat Rates (d)$30to$150$90
MWh
Options6 (139)(133)Option Pricing ModelNatural gas to power correlation (e)10%to100%55%
Power and natural gas volatility (e)5%to710%358%
Financial transmission rights/Congestion revenue rights190 (25)165 Market Approach (f)Illiquid price differences between settlement points (g)$(35)to$20$(8)
MWh
Natural gas29 (30)(1)Income ApproachNatural gas basis (h)$—to$10$5
MMBtu
Illiquid delivery periods (i)$—to$5$2
MMBtu
Other (j)10 — 10 
Total$841 $(1,593)$(752)
____________
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(a)(i) Electricity purchase and sales contracts include power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO, and CAISO regions, (ii) Options consist of physical electricity options, spread options, and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO, and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts.
(b)The range of the inputs may be influenced by factors such as time of day, delivery period, season, and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount.
(c)Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices.
(d)Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability.
(e)Primarily based on the historical forward correlation and volatility within ERCOT and PJM.
(f)While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid.
(g)Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
(h)Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices.
(i)Primarily based on the historical forward natural gas fixed prices.
(j)Other includes contracts for coal and environmental allowances.

The following table presents the changes in fair value of Level 3 assets and liabilities:
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions)
Net liability balance at beginning of period$(884)$(1,104)$(752)$(1,044)
Total unrealized valuation gains (losses)(299)482 (443)194 
Purchases, issuances and settlements (a):
Purchases94 62 226 193 
Issuances(4)(7)(10)(24)
Settlements(12)57 (103)196 
Transfers into Level 3 (b)1 5 (4)(15)
Transfers out of Level 3 (b)157 (12)139 (4)
Net liabilities assumed in connection with the Energy Harbor Merger— — — (13)
Net change(63)587 (195)527 
Net liability balance at end of period$(947)$(517)$(947)$(517)
Unrealized valuation losses relating to instruments held at end of period$(340)$361 $(519)$(114)
____________
(a)Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.
(b)Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the three months ended September 30, 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 and natural gas derivatives where forward pricing inputs have become observable. For the nine months ended September 30, 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, natural gas and coal derivatives where forward pricing inputs have become observable. For the three months ended September 30, 2024, transfers into Level 3 primarily consist of natural gas derivatives where forward pricing inputs have become unobservable. For the nine months ended September 30, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of coal and natural gas derivatives where forward pricing inputs have become observable.

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Assets and Liabilities Recorded on a Non-Recurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventories, assets acquired and liabilities assumed in business combinations, goodwill and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale.

The Energy Harbor Merger was accounted for under the acquisition method which requires all assets acquired and liabilities assumed in the acquisition be recorded at fair value at the acquisition date. See Note 2 for additional information.

Fair Value of Debt
September 30, 2025December 31, 2024
Instrument:Fair Value HierarchyCarrying
Amount		Fair
Value		Carrying
Amount		Fair
Value
(in millions)
Long-term debt under the Vistra Operations Credit FacilitiesLevel 2$2,421 $2,461 $2,435 $2,478 
BCOP Credit FacilityLevel 3774 790 344 367 
Vistra Zero Term Loan B FacilityLevel 2687 687 685 697 
Vistra Operations Senior NotesLevel 211,636 11,954 12,366 12,428 
Energy Harbor Revenue BondsLevel 2415 437 414 431 
Equipment Financing AgreementsLevel 355 55 54 53 
Forward Repurchase ObligationLevel 31,314 1,314 1,335 1,335 

We determine fair value in accordance with accounting standards. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.

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12.    ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations (ARO) primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs. AROs are based on legal obligations associated with enacted law, regulatory, or contractual retirement requirements for which decommissioning timing and cost estimates are reasonably estimable.

The following table summarizes the changes to our current and noncurrent ARO liabilities for the nine months ended September 30, 2025 and 2024:
Nine Months Ended September 30, 2025Nine Months Ended September 30, 2024
Nuclear Plant Decommissioning
Land Reclamation, Coal Ash, and Other
TotalNuclear
Plant
Decommissioning
Land Reclamation, Coal Ash, and Other
Total
(in millions)
Liability at beginning of period$3,240 $838 $4,078 $1,742 $796 $2,538 
Additions:
Accretion (a)114 30 144 95 31 126 
Adjustment for change in estimates (b)11 (26)(15)— 18 18 
Adjustment for obligations assumed through acquisition— — — 1,368 — 1,368 
Reductions:
Payments— (61)(61)— (64)(64)
Liability at end of period3,365 781 4,146 3,205 781 3,986 
Less amounts due currently— (202)(202)— (102)(102)
Noncurrent liability at end of period$3,365 $579 $3,944 $3,205 $679 $3,884 
____________
(a)For the nine months ended September 30, 2025 and 2024, nuclear plant decommissioning accretion includes $70 million and $53 million, respectively, of accretion expense recognized in operating costs in the condensed consolidated statements of operations and $44 million and $42 million, respectively, reflected as a change in regulatory liability in the condensed 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 $(14) million and $7 million for the nine months ended September 30, 2025 and 2024, respectively.

Nuclear Decommissioning AROs

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 September 30, 2025, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $1.852 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.543 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $691 million recorded to the condensed consolidated balance sheets in other noncurrent liabilities and deferred credits since any excess funds in the NDT after decommissioning our Comanche Peak plant would be refunded to Oncor. During the three months ended September 30, 2025, we completed a nuclear decommissioning study for the Comanche Peak plant resulting in an increase to our nuclear plant decommissioning ARO of $11 million.

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The carrying value of our ARO for our PJM nuclear facilities was recorded at fair value on the Merger Date. ARO accretion expense attributable to the PJM nuclear facilities is reflected in operating costs in the condensed consolidated statements of operations. ARO estimates for the PJM nuclear facilities will be evaluated on an individual unit basis at least every five years unless triggering events warrant a more frequent review. Any changes in ARO estimates are recorded as an increase or decrease in ARO liability along with a corresponding change to asset retirement cost asset within property, plant, and equipment in the condensed consolidated balance sheets; however, if the ARO estimate decreases by more than the remaining ARO asset, the balance of the change is recorded as a reduction to operating costs in the condensed consolidated statement of operations.

13.    COMMITMENTS AND CONTINGENCIES

Guarantees

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

Letters of Credit

As of September 30, 2025, we had outstanding letters of credit totaling $2.782 billion as follows:

•$2.400 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;
•$257 million to support battery and solar development projects;
•$25 million to support executory contracts and insurance agreements;
•$86 million to support our REP financial requirements with the PUCT; and
•$14 million for other credit support requirements.

Surety Bonds

As of September 30, 2025, we had outstanding surety bonds totaling $995 million to support performance under various contracts and legal obligations in the normal course of business.

Litigation and Regulatory Proceedings

Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material.

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Litigation

Natural Gas Index Pricing Litigation — We, through our subsidiaries, and another company remain named as defendants in one consolidated putative class action lawsuit pending in federal court in Wisconsin claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading, and churn trading from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes. In April 2023, the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit Court) heard oral argument on an interlocutory appeal challenging the district court's order certifying a class. In August 2025, the Seventh Circuit Court vacated the district court's order certifying the class and remanded the case back to the district court for further consideration consistent with the Seventh Circuit Court's decision. The parties reached an agreement in principle to settle the case that is subject to court approval and, in November 2025, the plaintiffs filed a motion to begin the process of obtaining that approval. The settlement is for an amount that is not material to the consolidated financial statements.

Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius Energy Trust in July 2019. The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 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. We had opposed enactment of that subsidy legislation at the time, and the nuclear subsidies were repealed in 2021 prior to any subsidies being distributed. The U.S. Attorney's Office conducted an investigation into the activities related to the passage of HB6, and Energy Harbor received a grand jury subpoena in July 2020 requiring production of certain information related to that investigation. Energy Harbor completed its responses to that subpoena by December 2021. In August 2020, the Ohio Attorney General filed a civil Racketeer Influenced and Corrupt Organizations Act (RICO) complaint against FirstEnergy Corp. and various Energy Harbor companies related to passage of HB6 (State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al., Franklin County, Ohio Common Pleas Court Case No. 20CV006281 and State of Ohio ex rel. Dave Yost, Ohio Attorney General v. Energy Harbor Corp., et al., Franklin County, Ohio Common Pleas Court Case No. 20CV007386). Motions to dismiss those cases remain pending and the case is currently stayed.

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

Winter Storm Uri Legal Proceedings

Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, and the Texas Attorney General initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges for generators arising from the event, including performance and fuel and supply issues. We responded to all those investigatory requests. 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 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. 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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Moss Landing 300 Battery Fire

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site. We are working closely with all local, state, and federal regulatory authorities on the response, and we are investigating the cause of the fire. We are also responding to various regulatory bodies, including the CPUC, the EPA, and others investigating the incident. 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. As of September 30, 2025, we have incurred and accrued estimated expenses related to these activities of approximately $110 million for the recovery effort. See Note 1 for additional information.

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 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. Additionally, the Order states the U.S. Attorney General may request a stay of the litigation involving these rules while the EPA conducts its reviews. 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.

Greenhouse Gas Emissions (GHG)

In May 2023, the EPA released a proposal regulating power plant emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing. Units permanently retiring by January 1, 2032 are exempt from the rule. Given our previously announced coal unit retirement commitments, our Martin Lake and Oak Grove plants are the only coal units that are subject to this rule. Our Graham, Lake Hubbard, Stryker Creek and Trinidad oil/natural gas facilities are also regulated under this rule. None of our existing large or small combustion turbines are subject to this rule. Following finalization of the rule in May 2024, 17 petitions for review from various states, industry groups, and companies were filed in the D.C. Circuit Court along with multiple motions to stay the rule. We are participating in an industry coalition challenging the rule. Oral argument on the merits of the legal challenges to the rule was held in December 2024 before the D.C. Circuit Court. The D.C. Circuit 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 August 2025, the EPA issued a proposal that would repeal the agency's prior endangerment finding for all GHG emission standards for light-, medium-, and heavy-duty vehicles. The EPA also stated that for other rules that have relied on the endangerment finding it intends to initiate other rulemakings to address any overlapping issues.

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 eight-hour standard for ozone emissions during ozone season (May to September). As required under the Clean Air Act, 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, which the EPA disapproved 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 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 because the EPA will need to undertake a new rulemaking to re-impose a FIP on Texas. In addition, based on policy recent pronouncements from the Trump administration, the new EPA is reevaluating its approach to these Good Neighbor SIPs in general.

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In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS. In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP). The FIP applied to 22 states beginning with the 2023 ozone seasons. States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia, and West Virginia. Texas would be moved into the revised (and more restrictive) Group 3 trading program previously established in the Revised CSAPR Update Rule that includes emission budgets for 2023 that the EPA says are achievable through existing controls installed at power plants.

In June 2024, the U.S. Supreme Court granted a stay of the GNP FIP pending a review of the merits by the D.C. Circuit Court and any further appeal to the U.S. Supreme Court. As a result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP. In April 2025, after previously denying the EPA's request for abeyance, the D.C. Circuit Court granted an abeyance of the case challenging the GNP FIP addressing interstate transport for all covered states. The Trump administration has stated that it is reevaluating this FIP.

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

In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 SIP and a partial FIP. For SO2, the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. 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, and those cases are currently in abeyance. In May 2023, a proposed BART rule was published in the Federal Register that would withdraw the trading program provisions of the prior rule and would establish SO2 limits on six facilities in Texas, including Martin Lake and Coleto Creek. Under the current proposal, compliance would be required within three years for Martin Lake and five 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. Based on several statements by the Trump administration and executive orders, we expect that the regional haze proposals will not be finalized as previously proposed by the Biden administration. In May 2025, the EPA issued a proposed rule for reasonable progress requirements that would (a) approve portions of Texas' first planning period regional haze SIP and (b) approve Texas' second planning period regional haze SIP. Under the EPA's proposals, no new controls would be required. We submitted comments in July 2025.

SO2 Designations for Texas

In November 2016, the EPA finalized nonattainment designations for SO2 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 February 2022, we and the TCEQ entered into an agreed order to reduce SO2 emissions at the Martin Lake plant, and the TCEQ submitted the agreed order to the EPA as a SIP revision to address the designation. We and the State of Texas filed legal challenges to the EPA's 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. If the EPA revises the designation on remand from the Fifth Circuit Court, the matter would be resolved and no additional controls would be required at Martin Lake as a result of the designation. In addition, based on the designations, in August 2024, the EPA proposed a Finding of Failure to attain the SO2 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 on the SIP 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. 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. Our petition remains in abeyance until November 2025 in the Fifth Circuit Court.

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Effluent Limitation Guidelines (ELGs)

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. Notifications were made to Texas, Illinois, and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. In May 2024, the EPA published the final ELG rule revisions, which contain new requirements for legacy wastewater and combustion residual leachate. The final rule also leaves in place the subcategory for facilities that permanently cease coal combustion by 2028. A number of parties have since challenged the rule and that case is pending in the U.S. Court of Appeals for the Eighth Circuit. We are not a party to that litigation. In February 2025, the 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 October 2025, the EPA proposed 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 proposal also 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 proposal 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.

Coal Combustion Residuals (CCR) Rule Revisions and Extension Applications

In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a final rule establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The 2020 final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue).

Prior to the November 2020 deadline to seek extensions, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications.

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Legacy CCR Rulemaking

In May 2024, the EPA published a final rule that expands coverage of groundwater monitoring and closure requirements to the following two new categories of units: (a) legacy CCR surface impoundments which are CCR surface impoundments that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015 and (b) "CCR management units" (CCRMUs) which generally could encompass noncontainerized ash deposits greater than one ton and impoundments and landfills that closed prior to October 19, 2015. As part of the rule, the EPA identified numerous CCR management units across the country, including ten of our potential units. The Vermilion ash ponds discussed below are the only unit which we believe qualify as a legacy CCR surface impoundment and given our closure plan for that site we do not believe the rule will have any impact on that site. CCRMUs with 1,000 or more tons of CCR must comply with the CCR's groundwater monitoring, corrective action, closure and post-closure requirements. For CCRMUs, complete facility evaluation reports are due within 33 months after publication of the rule, initial groundwater reports are due January 31, 2029, and the deadline to initiate closure, if needed, will start in 2029. Closure of the CCRMUs may also be deferred beyond those dates depending on certain factors, including where the CCRMU is located beneath critical infrastructure. In addition, certain closures may not be required when closure was previously approved under a state program. Because facility evaluation reports will determine our unit-specific compliance obligations, we cannot determine them at this time. In August 2024, we, along with USWAG, several other generating companies, and 17 states, including Texas, filed a challenge to the rule in the D.C. Circuit Court. In February 2025, the D.C. Circuit Court granted an unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 120 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. In July 2025, the EPA, through a direct final rule and companion proposed rule, extended the deadlines for the Facility Evaluation Reports (FER) to 2027, groundwater monitoring to 2029, and closure requirements to 2030 for the CCRMU provisions of the rule. The direct final rule was withdrawn on September 4, 2025, but the companion proposal would similarly extend the CCRMU deadlines if finalized by the EPA. The EPA has stated that it plans to publish a proposed rule to revise the CCR rule by January 30, 2026, and a final rule by October 30, 2026. The case challenging the rule is in abeyance until December 2025.

MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility.

At our retired Vermilion facility, 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. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash. These proposed closure costs are reflected in the ARO in the condensed consolidated balance sheets (see Note 17 for additional information).

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule.

In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of guidelines, rules, and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal at any site. In 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.

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For all of the above CCR matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not require removal. However, the rule required us to undertake further site-specific evaluations required by each program. We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been approved by the IEPA 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 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

After the 2015-2016 planning resource auction (PRA) was conducted by MISO, in which Zone 4 separated from the rest of MISO, parties including Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as unjust and unreasonable. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA.

In July 2019, the FERC issued an order denying complaints. Upon appeal, in 2021, the D.C. Circuit Court of Appeals remanded the case back to the FERC on a narrow question. In June 2024, the FERC ordered the matter set for an evidentiary hearing (a trial before a FERC administrative law judge) to determine what the FERC cited as "disputed issues of material fact" and held the hearing in abeyance for the parties to engage in settlement discussions. In August 2025, FERC approved the settlement agreement that resolved all remaining allegations among the parties and Vistra made a settlement payment to MISO for an amount that is not material to the consolidated financial statements. This matter is now resolved.

Other Matters

We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.

Nuclear Insurance Updates

In April 2025, we updated our nuclear accident decontamination and reactor damage stabilization insurance for our Beaver Valley, Davis-Besse and Perry facilities to $2.25 billion each and non-nuclear accident related property damage to $1.0 billion each. Prior to the April 2025 update, our nuclear accident decontamination and reactor damage stabilization insurance and non-nuclear accident related property damage for Beaver Valley, Davis-Besse and Perry was $1.5 billion each. Coverage is subject to a $10 million deductible per accident including natural hazards except for the Davis-Besse facility which has a $20 million deductible. Losses excluded or above such limits are self insured.

Also in April 2025, we updated our accidental outage insurance for our Beaver Valley and Perry facilities. Coverage provides for weekly payments per unit of up to $4.5 million (previously $2.5 million) for the first 52 weeks and up to $2.7 million (previously $1.5 million) for the remaining 21 weeks for non-nuclear and up to $3.6 million for a remaining 71 weeks (previously $2 million for a remaining 110 weeks) for nuclear accident property damage outages. The total maximum coverage is $291 million (previously $208 million) for non-nuclear accident property damage and $490 million (previously $350 million) for nuclear accident property damage outages.

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14.    EQUITY

Common Stock

Common Stock Dividends

Dividends are subject to declaration by the Board and may be subject to numerous factors at the time of declaration. These factors include, but are not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law, and any contractual limitations, such as the cumulative dividend requirements described in the certificates of designation of our outstanding preferred stock. Dividends per common share totaled $0.2260 and $0.2195 for the three months ended September 30, 2025 and 2024, respectively, and $0.6745 and $0.6520 for the nine months ended September 30, 2025 and 2024, respectively.

In October 2025, the Board declared a quarterly dividend of $0.2270 per share of common stock that will be paid in December 2025.

Share Repurchase Program

As of September 30, 2025, the Board had authorized a $6.750 billion share repurchase program. In October 2025, the Board authorized an incremental amount of $1.0 billion for repurchases under the share repurchase program. Through October 31, 2025, 164,896,651 shares, at an average price of $33.81 per share, have been repurchased under this program. The following table provides information about our repurchases of common stock for the period between January 1, 2025 and October 31, 2025:
$6.750 Billion Board Authorization
Total Number of Shares RepurchasedAverage Price Paid
Per Share		Amount Paid for Shares RepurchasedAmount Available for Additional Repurchases at the End of the Period
(in millions, except share amounts and price paid per share)
Three Months Ended March 31, 20252,437,700$137.66 $336 
Three Months Ended June 30, 20251,776,176132.72 236 
Three Months Ended September 30, 2025 (a)955,216197.74 188 
Nine Months Ended September 30, 20255,169,092$147.07 $760 $1,249 
October 1, 2025 through October 31, 2025371,820199.20 74 
January 1, 2025 through October 31, 20255,540,912$150.56 $834 $2,175 
____________
(a)Shares repurchased include 15,956 of unsettled shares for $3 million as of September 30, 2025.


Preferred Stock

The following is a summary of our cumulative redeemable preferred stock outstanding. In the event of liquidation or dissolution of the Company, the payment of dividends and the distribution of assets to preferred stockholders takes precedence over the Company's common stockholders.
Preferred Stock SeriesIssuance
Date		Shares
Issued		Shares OutstandingContractual
Rates		Earliest Redemption Date (a)Date at Which Dividend Rate Becomes FloatingFloating Annual Rates
Series AOctober 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 BDecember 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 CDecember 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)Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.

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Each series of preferred stock has a liquidation price of $1,000, plus accrued and unpaid dividends through their redemption date. Preferred stock is not convertible into or exchangeable for any other securities of the Company and has limited voting rights.

Preferred Stock Dividends

Preferred stock dividends are payable semiannually in arrears when declared by the Board. The following table summarizes preferred stock dividends paid per share for the three and nine months ended September 30, 2025 and 2024.
Three Months Ended September 30,Nine Months Ended September 30,
Preferred Stock Series2025202420252024
Series A Preferred Stock$— $— $40.000 $40.000 
Series B Preferred Stock$— $— $35.000 $35.000 
Series C Preferred Stock$44.375 $48.320 $88.750 $48.320 

In July 2025, the Board declared a semi-annual dividend of $40.000 per share of Series A Preferred Stock that was paid in October 2025. In October 2025, the Board declared (i) a semi-annual dividend of $35.000 per share on Series B Preferred Stock that will be paid in December 2025, and (ii) a semi-annual dividend of $44.375 per share on Series C Preferred Stock that will be paid in January 2026.

15.    EARNINGS PER SHARE

Basic earnings per share available to common stockholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions, except share data)
Net income attributable to Vistra$652 $1,888 $711 $2,218 
Less cumulative dividends attributable to Series A Preferred Stock(20)(20)(60)(60)
Less cumulative dividends attributable to Series B Preferred Stock(17)(17)(52)(52)
Less cumulative dividends attributable to Series C Preferred Stock(11)(11)(32)(32)
Net income attributable to common stock — basic and diluted604 1,840 $567 $2,074 
Weighted average shares of common stock outstanding:
Basic338,749,454 342,969,916 339,313,294 346,315,125 
Dilutive securities: Stock-based incentive compensation plan6,285,706 7,233,776 6,990,323 7,490,812 
Diluted345,035,160 350,203,692 346,303,617 353,805,937 
Net income per weighted average share of common stock outstanding:
Basic$1.78 $5.36 $1.67 $5.99 
Diluted$1.75 $5.25 $1.64 $5.86 

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 308 and 531 shares in the three months ended September 30, 2025 and 2024, respectively, and 103 and 11,210 shares for the nine months ended September 30, 2025 and 2024, respectively.

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16.    SEGMENT INFORMATION

The operations of Vistra are aligned into five reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. Our Chief Executive Officer is our chief operating decision maker (CODM). Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources. 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 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. 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 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 Moss Landing 300 facility was transferred to the Asset Closure segment in the first quarter of 2025 as a result of the Moss Landing Incident.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired generation facilities and mines. 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 6 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 decommissioning and reclaiming retired generation facilities, including mines.

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 to the Financial Statements in our 2024 Form 10-K. Our CODM uses more than one measure to assess segment performance, but primarily focuses on Adjusted EBITDA. While we believe this is a useful metric in evaluating operating performance, it is not a metric defined by U.S. GAAP and may not be comparable to non-GAAP metrics presented by other companies. Adjusted EBITDA is most comparable to consolidated Net income (loss) prepared based on U.S. GAAP. 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. Certain shared services costs are allocated to the segments. Substantially all income tax (expense) benefit is recognized in Corporate and Other.

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Three Months Ended September 30, 2025
RetailTexasEastWestAsset ClosureTotal Reportable SegmentsCorporate and OtherTotal
(in millions)
Operating revenues$4,139 $1,799 $1,750 $165 $2 $7,855 $(2,884)$4,971 
Fuel, purchased power costs, and delivery fees (a)
(3,815)(544)(866)(32)— (5,257)2,887 (2,370)
Operating costs(54)(243)(338)(15)(12)(662)7 (655)
Selling, general, and administrative expenses(270)(38)(59)(2)(16)(385)(59)(444)
Other segment items:
Depreciation and amortization(23)(160)(244)(14)— (441)(19)(460)
Interest expenses and related charges(18)9 16 2 (1)8 (294)(286)
Income tax expense— — — — — — (204)(204)
Other (b)
1 — 95 1 1 98 2 100 
Net income (loss)$(40)$823 $354 $105 $(26)$1,216 $(564)$652 
____________
(a)Includes nuclear fuel amortization of $35 million and $94 million, respectively, in the Texas and East segments.
(b)Other includes impairment of long-lived assets and other income, net.

Three Months Ended September 30, 2024
RetailTexasEastWestAsset ClosureTotal Reportable SegmentsCorporate and OtherTotal
(in millions)
Operating revenues$4,251 $4,244 $1,853 $232 $11 $10,591 $(4,303)$6,288 
Fuel, purchased power costs, and delivery fees (a)
(5,117)(487)(859)(45)(2)(6,510)4,303 (2,207)
Operating costs(47)(242)(296)(11)(19)(615)(1)(616)
Selling, general, and administrative expenses(266)(40)(32)(8)(9)(355)(56)(411)
Other segment items:
Depreciation and amortization(31)(155)(241)(15)(7)(449)(17)(466)
Interest expenses and related charges(16)11 4 1 (1)(1)(331)(332)
Income tax expense— — — — — — (555)(555)
Other (b)
— 23 97 1 7 128 8 136 
Net income (loss)$(1,226)$3,354 $526 $155 $(20)$2,789 $(952)$1,837 
____________
(a)Includes nuclear fuel amortization of $28 million and $95 million, respectively, in the Texas and East segments.
(b)Other includes other income, net.

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Nine Months Ended September 30, 2025
RetailTexasEastWestAsset ClosureTotal Reportable SegmentsCorporate and OtherTotal
(in millions)
Operating revenues$10,839 $3,797 $4,610 $347 $26 $19,619 $(6,465)$13,154 
Fuel, purchased power costs, and delivery fees (a)
(8,848)(1,509)(2,784)(119)— (13,260)6,469 (6,791)
Operating costs(131)(778)(1,020)(45)(113)(2,087)6 (2,081)
Selling, general, and administrative expenses(769)(122)(175)(11)(52)(1,129)(125)(1,254)
Other segment items:
Depreciation and amortization(70)(477)(876)(45)2 (1,466)(57)(1,523)
Interest expenses and related charges(53)41 36 4 (3)25 (933)(908)
Income tax expense
— — (1)— — (1)(103)(104)
Other (b)
1 14 194 1 3 213 5 218 
Net income (loss)$969 $966 $(16)$132 $(137)$1,914 $(1,203)$711 
Capital expenditures, including nuclear fuel and excluding growth expenditures (c)
$10 $714 $444 $117 $— $1,285 $411 $1,696 
____________
(a)Includes nuclear fuel amortization of $96 million and $270 million, respectively, in the Texas and East segments.
(b)Other includes impairment of long-lived assets and other income, net.
(c)Corporate and other includes $380 million of nuclear fuel purchases.

Nine Months Ended September 30, 2024
RetailTexasEastWestAsset ClosureTotal Reportable SegmentsCorporate and OtherTotal
(in millions)
Operating revenues$9,913 $4,924 $4,241 $701 $29 $19,808 $(6,621)$13,187 
Fuel, purchased power costs, and delivery fees (a)
(8,724)(1,249)(2,000)(164)(5)(12,142)6,622 (5,520)
Operating costs(118)(753)(774)(39)(56)(1,740)(2)(1,742)
Selling, general, and administrative expenses(715)(116)(93)(14)(34)(972)(165)(1,137)
Other segment items:
Depreciation and amortization(85)(423)(684)(43)(21)(1,256)(50)(1,306)
Interest expenses and related charges(38)33 4 1 (3)(3)(740)(743)
Income tax expense— — — — — — (694)(694)
Other (b)
(1)29 177 — 14 219 58 277 
Net income (loss)$232 $2,445 $871 $442 $(76)$3,914 $(1,592)$2,322 
Capital expenditures, including nuclear fuel and excluding growth expenditures (c)
$3 $544 $393 $44 $1 $985 $486 $1,471 
____________
(a)Includes nuclear fuel amortization of $80 million and $189 million, respectively, in the Texas and East segments.
(b)Other includes other income, net and the impacts of the Tax Receivable Agreement.
(c)Corporate and other includes $445 million of nuclear fuel purchases.

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17.    SUPPLEMENTARY FINANCIAL INFORMATION

Other Income, Net
Three Months Ended September 30,Nine Months Ended September 30,
2025202420252024
(in millions)
NDT net income (a)$100 $95 $197 $170 
Insurance settlements (b)— 21 80 22 
Gain on sale of land— 5 — 6 
Gain on TRA settlement (c)— — — 10 
Interest income4 9 14 50 
All other1 6 — 24 
Total other income, net$105 $136 $291 $282 
____________
(a)Includes interest, dividends, and net realized and unrealized gains (losses) associated with NDTs of the PJM nuclear facilities. Reported in the East segment.
(b)The $80 million of insurance settlements recognized in 2025 represents the involuntary conversion gain for Martin Lake Incident insurance proceeds reported in the Texas segment. See Note 1 for additional information.
(c)Reported in Corporate and Other.

Inventories by Major Category
September 30, 2025December 31, 2024
(in millions)
Materials and supplies$560 $533 
Fuel stock370 403 
Natural gas in storage40 34 
Total inventories$970 $970 

Investments
September 30, 2025December 31, 2024
(in millions)
Nuclear decommissioning trusts$4,930 $4,440 
Assets related to employee benefit plans13 14 
Land investments42 42 
Other investments23 16 
Total investments$5,008 $4,512 

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Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:
September 30, 2025December 31, 2024
(in millions)
Retirement and other employee benefits$200 $224 
Identifiable intangible liabilities141 155 
Regulatory liability (a)691 452 
Operating lease liabilities72 98 
Finance lease liabilities217 218 
Liability for third-party remediation8 8 
Accrued severance costs34 36 
Tax Receivable Agreement obligation9 14 
Other accrued expenses82 65 
Total other noncurrent liabilities and deferred credits$1,454 $1,270 
____________
(a)As of September 30, 2025 and 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 $691 million and $452 million, respectively.

Supplemental Cash Flow Information

The following table reconciles cash, cash equivalents and restricted cash reported in the condensed consolidated statements of cash flows to the amounts reported in the condensed consolidated balance sheets at September 30, 2025 and December 31, 2024:
September 30, 2025December 31, 2024
(in millions)
Cash and cash equivalents$602 $1,188 
Restricted cash included in current assets30 28 
Restricted cash included in noncurrent assets6 6 
Total cash, cash equivalents and restricted cash$638 $1,222 

The following table summarizes our supplemental cash flow information for the nine months ended September 30, 2025 and 2024. Non-cash investing and financing activities for the nine months ended September 30, 2024 includes activity related to the Energy Harbor Merger (see Note 2 for additional information).
Nine Months Ended September 30,
20252024
(in millions)
Cash payments related to:
Interest paid$799 $709 
Capitalized interest(86)(52)
Interest paid (net of capitalized interest)$713 $657 

For the nine months ended September 30, 2025 and 2024, we paid federal income tax of $11 million and $2 million, respectively, paid state income taxes of $70 million and $52 million respectively, and received state tax refunds of zero and $8 million, respectively.

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Item 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read together with the condensed consolidated financial statements and related notes included in Part I, Item 1 Financial Statements.

Significant Activities and Events, and Items Influencing Future Performance

Acquisition of Natural Gas Generation Facilities

On October 22, 2025 (Acquisition Date), pursuant to a purchase and sale agreement dated May 15, 2025, Vistra Operations acquired 100% of the membership interests of subsidiaries of Lotus (the Acquisition). The 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 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. See Note 2 to the Financial Statements for more information concerning the Acquisition.

Comanche Peak Power Purchase Agreement

In September 2025, Vistra entered into a 20-year power purchase agreement (with options to extend for up to an additional 20 years) with a large, investment grade company (the Customer), pursuant to which Vistra has agreed to supply to the Customer 1,200 MW of carbon-free power from the Comanche Peak Nuclear Power Plant. Vistra anticipates power delivery to begin in the fourth quarter of 2027 and ramp to full capacity by 2032.

Capacity Markets — PJM Auction Results

In July 2025, Vistra received its results from PJM's Reliability Pricing Model (RPM) auction results for planning year 2026-2027, and the table below lists clearing price per MW-day and our cleared capacity volumes by zone:
Clearing Price per MW-dayTotal
MW Cleared
RTO zone$329.17 3,969 
ComEd zone$329.17 2,082 
DEOK zone$329.17 952 
EMAAC zone$329.17 615 
MAAC zone$329.17 445 
ATSI zone$329.17 2,048 
DOM zone$329.17 203 
Total10,314 

Nuclear Plant License Renewal

In July 2025, our application for license renewal at our Perry Nuclear Plant was approved by the NRC. The license now extends through 2046.

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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 consolidated financial statements. 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.

Macroeconomic Conditions

Our industry is subject to uncertainties associated with the impact of rapidly evolving technology on U.S. electricity demand, as well as evolving political, regulatory and economic uncertainties.

Electricity Demand

Emerging electricity demand drivers including the rise of large-scale data centers, the electrification of oil field operations, and electric vehicle load building are contributing to a faster-paced load growth in the regions we serve. Our integrated retail electricity and power generation operations allows us to quickly respond to electricity demand changes. We are actively engaged in discussions with various counterparties regarding the potential long-term sale of power from both our operating nuclear and gas facilities as well as facilities in development to support large-scale electricity consumers.

Our business and these types of transactions are subject to inherent risks and uncertainties, including regulatory reviews, necessary approvals, and potential legislative actions. Such factors could affect the timing and feasibility of finalizing any definitive agreements with large scale electricity consumers.

Supply Chain Constraints

Our industry continues to face ongoing supply chain constraints and labor shortages, which have reduced the availability of essential equipment and supplies for constructing new generation facilities, increased lead times for procuring materials and raised labor costs associated with maintaining our natural gas, nuclear, and coal fleet.

We are proactively managing these constraints by continuously re-evaluating the business cases and timing of our planned development projects. This has led to the deferral or abandonment of some planned capital expenditures for our solar and battery projects and could impact the economic feasibility of additional projects in our new generation development pipeline. We are engaging with suppliers to secure key materials needed to maintain our existing generation facilities before future planned outages.

Russia/Ukraine Conflict

We are closely monitoring developments in the Russia and Ukraine conflict, specifically sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. The Prohibiting Russian Uranium Imports Act (PRUI Act), which was signed into law on August 11, 2024, prohibits importation of Russian uranium; however, the Department of Energy can issue waivers (subject to decreasing annual caps) until December 31, 2027 if there is no alternate source of low-enriched uranium available to keep U.S. nuclear reactors operating or is in the national interest. Additionally, passage of the PRUI Act enabled the allocation of $2.72 billion in federal funding to ramp up production of domestic uranium fuel. On November 15, 2024, the Russian Federation temporarily suspended shipments of uranium to the U.S., stating that they would grant future export licenses on a case-by-case basis.

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Our 2025 and 2026 refueling plans have not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel impacting our refueling schedules. All nuclear fuel requirements for 2025 and 2026 are either in inventory or are onshore. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance. We have nuclear fuel contracted to support all our refueling needs through 2030 without any additional Russian deliveries. We continue to take affirmative action by building strategic inventory and deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facilities through potential Russian supply disruption.

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, but the two other battery facilities remain offline as we continue to investigate the cause of the fire. We expect the Moss Landing 350 MW battery to return to service in late 2025 or early 2026. There is less certainty about the return to service regarding the Moss Landing 100 MW battery. We will know more after the investigation of the cause of the Moss Landing Incident is complete. As of September 30, 2025, the net book value of the Moss Landing 100 facility was approximately $165 million.

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 6 and 16 to the Financial Statements 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 $29 million on ASAOC activities through September 30, 2025. As of September 30, 2025, our accrual for estimated future costs for the ASAOC activities is approximately $81 million, of which, $68 million is reflected in other current liabilities and $13 million is reflected in other noncurrent liabilities and deferred credits in the condensed 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 and penalties under contracts. We are currently unable to estimate the full impact the Moss Landing Incident will have on us as our estimate will evolve as demolition progresses. See Note 13 to the Financial Statements 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. See Note 1 to the Financial Statements for additional information. Given uncertainty in timing of remaining insurance recoveries and additional expenses that could be incurred related to the fire, we cannot predict the full impact this event will have on our 2025 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. We expect the unit to return to service in late 2025 or early 2026. We estimate total cash capital expenditures required to restore the unit to service will be approximately $355 million, of which approximately $155 million in cash capital expenditures were incurred in the nine months ended September 30, 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. See Note 1 to the Financial Statements for additional information. Given uncertainty in timing of remaining insurance recoveries, we cannot predict the full impacts this event will have on our 2025 financial statements.

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Acquisition of Noncontrolling Interest

On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (as amended, the UPAs) with each of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (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 (collectively, the Transaction). The Transaction closed on December 31, 2024 and Vistra Vision Holdings now owns 100% of the equity interests in Vistra Vision. See Notes 2 and 9 to the Financial Statements for additional information.

Planned Gas-Fueled Dispatchable Power in ERCOT

In May 2024, we announced our intention to add up to 2,000 MW of dispatchable, natural gas-fueled electricity capacity in west, central, and north Texas consisting of the following projects:

•Building up to 860 MW of advanced simple-cycle peaking plants to be located in west Texas to support the increasing power needs of the region, including the state's oil and gas industry.
•Repowering the coal-fueled Coleto Creek Power Plant near Goliad, Texas, set to retire in 2027 to comply with EPA rules, as a natural-gas fueled plant with up to 600 MW of capacity.
•Completing upgrades at existing natural gas-fueled plants that will add more than 500 MW of summer capacity and 100 MW of winter capacity.

In July 2024, we filed applications with the PUCT under the Texas Energy Fund loan program seeking financing for the 860 MW of new advanced simple-cycle peaking plants referenced above. Both projects were selected for due diligence as part of the Texas Energy Fund loan program, which is ongoing. An invitation to due diligence does not mean an applicant is awarded a loan.

In September 2025, we announced we will move forward with construction of the 860 MW peaking plants discussed above. Early development work is underway, and we anticipate the units will be online in 2028.

Merger with Energy Harbor

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023, (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 and Avenue exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively, Energy Harbor Merger). The Energy Harbor Merger combined Energy Harbor's and Vistra's nuclear and retail businesses and certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free technologies (dispatchable and renewables/storage) and the retail business. The cash consideration for Energy Harbor Merger was funded by Vistra Operations using a combination of cash on hand and borrowings under the Commodity-Linked Facility, the Receivables Facility, and the Repurchase Facility. See Note 2 to the Financial Statements for additional information.

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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, new technology-neutral ITCs and PTCs that apply to various different clean energy technologies and a first-time stand-alone battery storage investment tax credit. The IRA also implements a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. The section 45U nuclear PTC is available to existing nuclear facilities from 2024 through 2032 and 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 (each subject to annual inflation adjustments). 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. As discussed in Note 1 to the Financial Statements in our 2024 Form 10-K, we recognized transferable nuclear PTC revenues of $545 million in the year ended December 31, 2024. As discussed in Note 4 to the Financial Statements, we recognized transferable nuclear PTC revenues of $145 million in each of the three and nine months ended September 30, 2025. U.S. Treasury regulations are expected to 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 estimates could result in a material change to PTC revenues recorded in 2024 and 2025 and would be reflected as a change in estimate in the period in which the guidance is received

Critical Accounting Policies and Estimates

The Company's discussion and analysis of its financial position and results of operations is based upon its condensed consolidated financial statements. The preparation of these condensed consolidated financial statements requires estimation and judgment that affect the reported amounts of revenue, expenses, assets, and liabilities. The Company bases its estimates on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the accounting for assets and liabilities that are not readily apparent from other sources. If the estimates differ materially from actual results, the impact in the condensed consolidated financial statements may be material. The Company's critical accounting policies are disclosed in our 2024 Form 10-K.

Results of Operations

Net income decreased $1.185 billion to $652 million for the three months ended September 30, 2025 compared to the three months ended September 30, 2024. Net income decreased $1.611 billion to $711 million for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024. For additional information see the following discussion of our results of operations.

EBITDA and Adjusted EBITDA

In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed (i) with our GAAP results and (ii) the accompanying reconciliations to corresponding GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.

These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition, an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review the condensed consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).

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Vistra Consolidated Financial Results — Three Months Ended September 30, 2025 Compared to the Three Months Ended September 30, 2024

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended September 30, 2025:
Three Months Ended September 30, 2025
RetailTexasEastWestAsset
Closure		Eliminations / Corporate and OtherVistra
Consolidated
(in millions)
Operating revenues$4,139 $1,799 $1,750 $165 $2 $(2,884)$4,971 
Fuel, purchased power costs and delivery fees(3,815)(544)(866)(32)— 2,887 (2,370)
Operating costs(54)(243)(338)(15)(12)7 (655)
Depreciation and amortization(23)(160)(244)(14)— (19)(460)
Selling, general and administrative expenses(270)(38)(59)(2)(16)(59)(444)
Impairment of long-lived assets— — (5)— — — (5)
Operating income (loss)(23)814 238 102 (26)(68)1,037 
Other income, net1 — 100 1 1 2 105 
Interest expense and related charges(18)9 16 2 (1)(294)(286)
Income (loss) before income taxes(40)823 354 105 (26)(360)856 
Income tax expense— — — — — (204)(204)
Net income (loss)$(40)$823 $354 $105 $(26)$(564)$652 
Income tax expense— — — — — 204 204 
Interest expense and related charges (a)18 (9)(16)(2)1 294 286 
Depreciation and amortization (b)23 195 338 14 — 18 588 
EBITDA before Adjustments1 1,009 676 117 (25)(48)1,730 
Unrealized net (gain) loss resulting from commodity hedging transactions
20 (239)93 (57)(1)— (184)
Purchase accounting impacts8 1 8 — — — 17 
Non-cash compensation expenses— — — — — 36 36 
Transition and merger expenses3 — 3 — — 16 22 
Impairment of long lived assets— — 5 — — — 5 
Decommissioning-related activities (c)
— 5 (74)1 6 — (62)
ERP system implementation expenses— — 1 — — — 1 
Other, net
5 8 7 2 3 (26)(1)
Adjusted EBITDA$37 $784 $719 $63 $(17)$(22)$1,564 
____________
(a)Includes $10 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $35 million and $94 million, respectively, in the Texas and East segments.
(c)Represents net of all NDT (income) loss of the PJM nuclear facilities and all ARO and environmental remediation expenses.

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The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended September 30, 2024:
Three Months Ended September 30, 2024
RetailTexasEastWestAsset
Closure		Eliminations / Corporate and OtherVistra
Consolidated
(in millions)
Operating revenues$4,251 $4,244 $1,853 $232 $11 $(4,303)$6,288 
Fuel, purchased power costs and delivery fees(5,117)(487)(859)(45)(2)4,303 (2,207)
Operating costs(47)(242)(296)(11)(19)(1)(616)
Depreciation and amortization(31)(155)(241)(15)(7)(17)(466)
Selling, general and administrative expenses(266)(40)(32)(8)(9)(56)(411)
Operating income (loss)(1,210)3,320 425 153 (26)(74)2,588 
Other income, net
— 23 97 1 7 8 136 
Interest expense and related charges(16)11 4 1 (1)(331)(332)
Income (loss) before income taxes(1,226)3,354 526 155 (20)(397)2,392 
Income tax expense— — — — — (555)$(555)
Net income (loss)$(1,226)$3,354 $526 $155 $(20)$(952)$1,837 
Income tax expense— — — — — 555 555 
Interest expense and related charges (a) 16 (11)(4)(1)1 331 332 
Depreciation and amortization (b)31 183 336 15 7 17 589 
EBITDA before Adjustments(1,179)3,526 858 169 (12)(49)3,313 
Unrealized net (gain) loss resulting from commodity hedging transactions
1,275 (2,773)(254)(101)(2)— (1,855)
Purchase accounting impacts1 1 (4)— — — (2)
Non-cash compensation expenses— — — — — 23 23 
Transition and merger expenses— 1 1 — — 23 25 
Decommissioning-related activities (c)— 8 (72)(1)1 — (64)
ERP system implementation expenses1 1 — — 1 — 3 
Other, net4 (2)— 3 1 (22)(16)
Adjusted EBITDA$102 $762 $529 $70 $(11)$(25)$1,427 
____________
(a)Includes $84 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $28 million and $95 million, respectively, in the Texas and East segments.
(c)Represents net of all NDT (income) loss, ARO accretion expense for operating assets, and ARO remeasurement impacts for operating assets.

GAAP Net income decreased $1.185 billion to $652 million for the three months ended September 30, 2025 compared to the three months ended September 30, 2024. The primary drivers for the decrease in GAAP Net income include:

Unfavorable impacts:

•A decrease of $1.671 billion in unrealized mark-to-market gains on commodity derivative positions. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.
•An increase of $39 million in operating costs due primarily to increased plant maintenance and outage expenses.
•An increase of $33 million in selling, general and administrative expenses due primarily to stock-based incentive compensation expense and technology and consulting costs.
•A decrease of $31 million in other income, net due primarily to a decrease in insurance income.
•An increase of $5 million in impairment of long-lived assets related to certain development projects in the three months ended September 30, 2025.

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Favorable impacts:

•An increase of $191 million in realized revenue net fuel due primarily to nuclear PTC revenue of $145 million recognized in the three months ended September 30, 2025 and higher realized energy and capacity prices partially offset by lower energy production due to the Martin Lake Incident and higher retail supply costs outside of ERCOT.
•A decrease in interest expense due primarily to a decrease in unrealized mark-to-market net losses on interest rate swaps.
•A decrease in income tax expense due to lower pre-tax income.

The following table presents the operational performance of our retail and generation segments:
Three Months Ended September 30,
RetailTexasEastWest
20252024202520242025202420252024
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT23,12122,193
Sales volumes in Northeast/Midwest16,94117,864
Total retail electricity sales volumes40,06240,057
Production volumes (GWh):
Natural gas facilities15,45515,15216,90217,135582996
Lignite and coal facilities6,2237,0225,0804,991
Nuclear facilities5,0285,2178,5448,677
Solar facilities21223380
Capacity factors:
CCGT facilities73.7 %78.3 %69.5 %70.5 %25.8 %44.2 %
Lignite and coal facilities58.5 %70.7 %58.6 %57.5 %
Nuclear facilities94.9 %98.5 %95.6 %97.1 %
Weather - percent of normal (a):
Cooling degree days95%100 %97 %102 %91 %97 %94 %98 %
Heating degree days— %— %— %— %61 %64 %— %— %
____________
(a)Reflects cooling degree or heating degree days based on Weather Services International (WSI) data. A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base temperature. Retail amounts represent weather data for the Dallas-Fort Worth area.

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Three Months Ended September 30,Three Months Ended September 30,
2025202420252024
Average Power Price ($MWh) (a):Average Natural gas price ($MWh) (b):
ERCOT North Hub$32.61 $26.87 NYMEX Henry Hub$3.03 $2.08 
ERCOT West Hub$35.47 $29.22 Houston Ship Channel$2.69 $1.79 
PJM AEP Dayton Hub$43.51 $32.22 Permian Basin$0.49 $(1.01)
PJM Northern Illinois Hub$42.80 $28.84 Dominion South$2.13 $1.41 
PJM Western Hub$46.82 $37.10 Tetco ELA$2.83 $1.95 
MISO Indiana Hub$46.93 $32.33 Chicago Citygate$2.77 $1.78 
ISONE Massachusetts Hub$50.19 $38.08 Tetco M3$2.27 $1.50 
New York Zone A$48.75 $32.48 Algonquin Citygates$2.96 $1.75 
CAISO NP15$41.30 $41.79 PG&E Citygate$3.47 $2.79 
___________
(a)    Reflects the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we realized.
(b)Reflects the average around-the-clock settled prices for the periods presented and does not reflect costs incurred by us.

Adjusted EBITDA for the three months ended September 30, 2025 compared to the three months ended September 30, 2024 increased by $137 million. The primary drivers for the increase include:
Three Months Ended September 30, 2025
Compared to 2024
RetailTexasEastWest
(in millions)
Favorable change in realized revenue net of fuel in East driven by higher realized energy and capacity prices. Favorable change in Texas driven by nuclear PTC revenue and higher realized prices partially offset by lower energy production due to the Martin Lake Incident.
$— $41 $238 $(9)
Unfavorable change in retail margins driven by higher supply costs outside of ERCOT
(72)— — — 
Favorable change in consumption due to weather impacts
11 
Increase in plant operating costs due primarily to increased outage expenses— (1)(34)(4)
Change in SG&A and other in Retail due primarily to higher retail revenues in ERCOT. Change in Texas and East SG&A and other due to higher technology and consulting costs.
(4)(18)(14)6 
Change in Adjusted EBITDA$(65)$22 $190 $(7)
Change in depreciation and amortization driven primarily by an increase in capital additions in Texas and East8 (12)(2)1 
Change in unrealized net gains (losses) on hedging activities (a)1,255 (2,534)(347)(44)
Impairment of long-lived assets— — (5)— 
Decommissioning related activities— 3 2(2)
Other (including interest expenses)(12)(10)(10)2 
Change in Net income (loss)$1,186 $(2,531)$(172)$(50)
___________
(a)    See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.

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Vistra Consolidated Financial Results — Nine Months Ended September 30, 2025 Compared to the Nine Months Ended September 30, 2024

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the nine months ended September 30, 2025:
Nine Months Ended September 30, 2025
RetailTexasEastWestAsset
Closure		Eliminations / Corporate and OtherVistra
Consolidated
(in millions)
Operating revenues$10,839 $3,797 $4,610 $347 $26 $(6,465)$13,154 
Fuel, purchased power costs, and delivery fees(8,848)(1,509)(2,784)(119)— 6,469 (6,791)
Operating costs(131)(778)(1,020)(45)(113)6 (2,081)
Depreciation and amortization(70)(477)(876)(45)2 (57)(1,523)
Selling, general, and administrative expenses(769)(122)(175)(11)(52)(125)(1,254)
Impairment of long-lived assets— (68)(5)— — — (73)
Operating income (loss)1,021 843 (250)127 (137)(172)1,432 
Other income, net1 82 199 1 3 5 291 
Interest expense and related charges(53)41 36 4 (3)(933)(908)
Income (loss) before income taxes969 966 (15)132 (137)(1,100)815 
Income tax expense
— — (1)— — (103)(104)
Net income (loss)$969 $966 $(16)$132 $(137)$(1,203)$711 
Income tax expense
— — 1 — — 103 104 
Interest expense and related charges (a)53 (41)(36)(4)3 933 908 
Depreciation and amortization (b)70 573 1,146 45 (2)57 1,889 
EBITDA before Adjustments1,092 1,498 1,095 173 (136)(110)3,612 
Unrealized net (gain) loss resulting from commodity hedging transactions(136)(109)621 (7)(2)— 367 
Purchase accounting impacts16 1 31 — — — 48 
Non-cash compensation expenses— — — — — 82 82 
Transition and merger expenses8 — 4 — — 50 62 
Impairment of long-lived assets— 68 5 — — — 73 
Insurance income (c)— (80)— — (21)— (101)
Decommissioning-related activities (d)— 14 (120)1 95 — (10)
ERP system implementation expenses3 3 4 — 1 — 11 
Other, net (e)(6)21 11 7 5 (70)(32)
Adjusted EBITDA$977 $1,416 $1,651 $174 $(58)$(48)$4,112 
____________
(a)Includes $84 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $96 million and $270 million, respectively, in the Texas and East segments.
(c)Includes involuntary conversion gain recognized from Martin Lake Incident property damage insurance in the Texas segment and revenues from Moss Landing Incident business interruption proceeds in the Asset Closure segment.
(d)Represents net of all NDT (income) loss of the PJM nuclear facilities and all ARO and environmental remediation expenses.
(e)Includes the final application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri in the Retail segment.

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The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the nine months ended September 30, 2024:
Nine Months Ended September 30, 2024
RetailTexasEastWestAsset
Closure		Eliminations / Corporate and OtherVistra
Consolidated
(in millions)
Operating revenues$9,913 $4,924 $4,241 $701 $29 $(6,621)$13,187 
Fuel, purchased power costs, and delivery fees(8,724)(1,249)(2,000)(164)(5)6,622 (5,520)
Operating costs(118)(753)(774)(39)(56)(2)(1,742)
Depreciation and amortization(85)(423)(684)(43)(21)(50)(1,306)
Selling, general, and administrative expenses(715)(116)(93)(14)(34)(165)(1,137)
Operating income (loss)271 2,383 690 441 (87)(216)3,482 
Other income (deductions), net(1)29 177 — 14 63 282 
Interest expense and related charges(38)33 4 1 (3)(740)(743)
Impacts of Tax Receivable Agreement— — — — — (5)(5)
Income (loss) before income taxes232 2,445 871 442 (76)(898)3,016 
Income tax expense— — — — — (694)(694)
Net income (loss)$232 $2,445 $871 $442 $(76)$(1,592)$2,322 
Income tax expense— — — — — 694 694 
Interest expense and related charges (a)38 (33)(4)(1)3 740 743 
Depreciation and amortization (b)85 503 873 43 21 50 1,575 
EBITDA before Adjustments355 2,915 1,740 484 (52)(108)5,334 
Unrealized net (gain) loss resulting from commodity hedging transactions489 (1,513)(385)(308)(8)— (1,725)
Purchase accounting impacts— 1 (8)— — (14)(21)
Impacts of Tax Receivable Agreement (c)— — — — — (5)(5)
Non-cash compensation expenses— — — — — 76 76 
Transition and merger expenses2 1 7 — — 75 85 
Decommissioning-related activities (d)— 19 (112)— 1 — (92)
ERP system implementation expenses
7 6 5 1 2 — 21 
Other, net10 4 (5)6 2 (85)(68)
Adjusted EBITDA$863 $1,433 $1,242 $183 $(55)$(61)$3,605 
____________
(a)Includes $26 million of unrealized mark-to-market net losses on interest rate swaps.
(b)Includes nuclear fuel amortization of $80 million and $189 million, respectively, in the Texas and East segments.
(c)Includes $10 million gain recognized on the repurchase of TRA Rights.
(d)Represents net of all NDT (income) loss, ARO accretion expense for operating assets, and ARO remeasurement impacts for operating assets.

GAAP Net income decreased $1.611 billion to $711 million for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024. The primary drivers for the decrease in GAAP Net income include:

Unfavorable impacts:

•An increase of $2.092 billion in unrealized mark-to-market losses on commodity derivative positions. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.
•An increase of $77 million in operating costs due to the Moss Landing Incident, net of expected insurance recoveries.
•An increase of $73 million in impairment of long-lived assets related to certain development projects in the nine months ended September 30, 2025.
•An increase in interest expense due primarily to higher debt balances and an increase in unrealized mark-to-market net losses on interest rate swaps

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Favorable impacts:

•Inclusion of nine months of Energy Harbor revenues net of expenses in the East and Retail segments for 2025 compared to seven months in 2024
•An increase in realized revenue net fuel due to higher realized energy and capacity prices in East, nuclear PTC revenue and higher retail margins driven by favorable power supply costs and customer count growth, partially offset by lower energy production due to the Martin Lake Incident.
•An increase in insurance income due primarily to $80 million of involuntary conversion gains on property damage insurance from the Martin Lake Incident and $22 million of business interruption revenue from the Moss Landing Incident recognized in the three months ended June 30, 2025 partially offset by $21 million of insurance income recognized in 2024.
•An increase of $27 million in NDT income due to realized and unrealized gains on equity securities.
•A decrease in income tax expense due to lower pre-tax income and a lower effective tax rate.

The following table presents the operational performance of our retail and generation segments:
Nine Months Ended September 30,
RetailTexasEastWest
20252024202520242025202420252024
Retail electricity sales volumes (GWh):
Sales volumes in ERCOT60,97157,234
Sales volumes in Northeast/Midwest45,68144,105
Total retail electricity sales volumes106,652101,339
Production volumes (GWh):
Natural gas facilities35,80034,50443,74244,2671,6292,921
Lignite and coal facilities16,53117,68214,27412,126
Nuclear facilities14,74715,26024,24018,438
Solar facilities587605191
Capacity factors:
CCGT facilities58.6 %60.6 %61.3 %60.7 %24.3 %43.5 %
Lignite and coal facilities52.4 %59.8 %55.5 %47.0 %
Nuclear facilities93.8 %96.7 %91.4 %88.7 %
Weather - percent of normal (a):
Cooling degree days98 %107 %104 %108 %94 %104 %93 %91 %
Heating degree days104 %86 %112 %89 %98 %85 %125 %121 %
____________
(a)Reflects cooling degree or heating degree days based on Weather Services International (WSI) data. A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base temperature. Retail amounts represent weather data for the Dallas-Fort Worth area.

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Nine Months Ended September 30,Nine Months Ended September 30,
2025202420252024
Average Power Price ($MWh) (a):Average Natural Gas Price ($MWh) (b):
ERCOT North Hub$31.85 $25.70 NYMEX Henry Hub$3.48 $2.19 
ERCOT West Hub$32.37 $27.51 Houston Ship Channel$2.96 $1.79 
PJM AEP Dayton Hub$43.99 $30.15 Permian Basin$1.13 $(0.13)
PJM Northern Illinois Hub$36.37 $25.74 Dominion South$2.72 $1.57 
PJM Western Hub$47.67 $33.53 Tetco ELA$3.25 $2.02 
MISO Indiana Hub$43.72 $31.82 Chicago Citygate$3.21 $2.09 
ISONE Massachusetts Hub$64.15 $37.10 Tetco M3$3.70 $1.98 
New York Zone A$50.96 $30.59 Algonquin Citygates$5.85 $2.56 
CAISO NP15$36.27 $38.52 PG&E Citygate$3.33 $2.97 
___________
(a)    Reflects the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we realized.
(b)Reflects the average around-the-clock settled prices for the periods presented and does not reflect costs incurred by us.

Adjusted EBITDA for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 increased by $507 million. The primary drivers for the increase include:
Nine Months Ended September 30, 2025 Compared to 2024
Retail (a)TexasEast (a)West
(in millions)
Favorable change in realized revenue net of fuel driven primarily by inclusion of a full nine months of Energy Harbor results and higher realized energy and capacity prices in East. Favorable change in Texas driven by nuclear PTC revenue and higher realized prices partially offset by lower energy production due to the Martin Lake Incident.
$— $34 $669 $(8)
Higher retail margins driven by favorable power supply costs, customer count growth, and inclusion of a full nine months of Energy Harbor retail contracts
138 — — — 
Favorable change in consumption primarily due to weather
23 — — — 
Increase in plant operating costs due primarily to inclusion of a full nine months of Energy Harbor results in East
— (20)(224)(6)
Change in SG&A and other primarily due to inclusion of a full nine months of Energy Harbor results in Retail and East
(47)(31)(36)5 
Change in Adjusted EBITDA$114 $(17)$409 $(9)
Change in depreciation and amortization driven primarily due to the inclusion of a full nine months of Energy Harbor results in East
15 (70)(273)(2)
Change in unrealized net gains (losses) on hedging activities (b)625 (1,404)(1,006)(301)
Impairment of long-lived assets— (68)(5)— 
Increase in other income due to involuntary conversion gain on Martin Lake Incident— 80 $— — 
Decommissioning related activities— 5 8(1)
Other (including interest expenses)(17)(5)(20)3 
Change in Net income (loss)$737 $(1,479)$(887)$(310)
___________
(a)    Includes amounts associated with operations acquired in the Energy Harbor Merger beginning March 1, 2024.
(b)    See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.

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Asset Closure Segment — Three and Nine Months Ended September 30, 2025 Compared to Three and Nine Months Ended September 30, 2024
Three Months Ended September 30,Favorable (Unfavorable)
Change		Nine Months Ended September 30,Favorable (Unfavorable)
Change
2025202420252024
(in millions)
Operating revenues$2 $11 $(9)$26 $29 $(3)
Fuel, purchased power costs, and delivery fees— (2)2 $— $(5)$5 
Operating costs$(12)$(19)$7 (113)(56)(57)
Depreciation and amortization— (7)7 2 (21)23 
Selling, general, and administrative expenses(16)(9)(7)(52)(34)(18)
Operating loss(26)(26)— (137)(87)(50)
Other income (deductions), net1 7 (6)3 14 (11)
Interest expense and related charges(1)(1)— (3)(3)— 
Loss before income taxes(26)(20)(6)(137)(76)(61)
Net loss$(26)$(20)$(6)$(137)$(76)$(61)
Adjusted EBITDA$(17)$(11)$(6)$(58)$(55)$(3)

GAAP results for the nine months ended months ended September 2025 are unfavorable compared to the nine months ended months ended September 2024 primarily due to costs associated with the Moss Landing Incident net of insurance receivables. Adjusted EBITDA for the nine months ended months ended September 2025 is unfavorable compared to the nine months ended months ended September 2024 primarily due to a decrease in revenue due to the Moss Landing Incident. See Note 1 to the Financial Statements for additional information.

Energy-Related Commodity Contracts and Mark-to-Market Activities

As we entered the 2024 and 2025 calendar years, we had substantially all of our expected generation volumes hedged. This strategic hedging allowed us to lock in margins that were higher than what we would have realized if we had not hedged. These margins also exceeded those from hedging activities for the nine months ended September 30, 2024, contributing to the increase in realized revenue net of fuel in our generation segments, along with the addition of Energy Harbor.

The changes in unrealized gains and losses on hedging activities are driven by forward power sales. When power prices increase or decrease compared to what our generation segments have sold forward, the generation segments recognize unrealized losses or gains, respectively. Conversely, the retail segment, which procures power from the generation segments to meet future load obligations, experiences an inverse effect on unrealized mark-to-market valuations compared to the generation segments.

During the three and nine months ended September 30, 2025 and 2024, forward power price curves decreased relative to our hedged positions resulting in unrealized gains in the Texas and West segments.

During the three and nine months ended September 30, 2025, forward power price curves in the East segment increased relative to our hedged positions resulting in unrealized losses compared to a decrease in power price curves resulting in unrealized gains in the three and nine months ended September 30, 2024.

These unrealized gains and losses in the Texas, East and West generation segments across these comparative periods were partially offset by unrealized gains and losses in the Retail segment across the same periods.

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The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2025 and 2024.
Nine Months Ended September 30,
20252024
(in millions)
Commodity contract net liability as of January 1$(1,459)$(2,740)
Mark-to-market adjustments:
Settlements/termination of positions (a)881 1,350 
Changes in fair value of positions in the portfolio (b)(1,248)375 
Net loss associated with mark-to-market accounting(367)1,725 
Acquired commodity contracts (c)— (50)
Other activity (d)82 111 
Commodity contract net liability as of September 30
$(1,744)$(954)
____________
(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains/(losses) recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(b)Represents unrealized net gains/(losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(c)Includes fair value of commodity contracts acquired in the Energy Harbor Merger (see Note 2 to the Financial Statements for additional information).
(d)Primarily represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.

The following maturity table presents the net commodity contract liability arising from recognition of fair values as of September 30, 2025, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
Maturity dates of unrealized commodity contract net liability as of September 30, 2025
Source of Fair ValueLess than
1 year		1-3 years4-5 yearsExcess of
5 years		Total
(in millions)
Prices actively quoted$(367)$(168)$9 $(1)$(527)
Prices provided by other external sources(208)(61)(1) (270)
Prices based on models(245)(567)(135) (947)
Total$(820)$(796)$(127)$(1)$(1,744)

We have engaged in natural gas hedging activities to mitigate the risk of higher or lower wholesale electricity prices that have corresponded to increases or declines in natural gas prices. When natural gas prices are elevated or depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.

Estimated hedging levels for generation volumes in our Texas, East, and West segments as of September 30, 2025 were as follows:
Balance of 2025
2026
Nuclear/Renewable/Coal Generation:
Texas100 %100 %
East98 %97 %
Natural Gas Generation:
Texas100 %88 %
East98 %100 %
West100 %69 %

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Financial Condition

Cash Flows

Operating Cash Flows

Cash provided by operating activities totaled $2.638 billion and $3.210 billion for the nine months ended September 30, 2025 and 2024, respectively. The unfavorable $572 million change was primarily driven by a $1.216 billion decrease in net cash flows related to margin deposits as $361 million in net margin deposits related to commodity contracts supporting our hedging strategy were posted for the nine months ended September 30, 2025 as compared to $855 million in net margin deposits returned for the nine months ended September 30, 2024. This unfavorable change was partially offset by higher realized revenue net of fuel cost driven primarily by inclusion of nine months of Energy Harbor revenues net of expenses for 2025 compared to seven months in 2024 and higher realized energy and capacity prices in the East segment.

Investing Cash Flows

Cash used in investing activities includes:
Nine Months Ended September 30,Increase (Decrease)
20252024
(in millions)
Capital expenditures, including LTSA prepayments$(836)$(602)$(234)
Nuclear fuel purchases(380)(445)65 
Growth and development expenditures(700)(601)(99)
Total capital expenditures(1,916)(1,648)(268)
Energy Harbor acquisition (net of cash acquired)— (3,065)3,065 
Net purchases of environmental allowances(454)(364)(90)
Proceeds from sale of property, plant and equipment, including nuclear fuel21 137 (116)
Insurance proceeds for recovery of damaged property, plant and equipment198 3 195 
Other investing activity(11)(22)11 
Cash used in investing activities$(2,162)$(4,959)$2,797 

The $2.797 billion change was primarily driven by $3.1 billion utilized to fund the Energy Harbor Merger in 2024 and $198 million of property damage insurance proceeds received from the Martin Lake Incident and Moss Landing Incident in 2025. These impacts were partially offset by higher capital expenditures associated with the Martin Lake Incident and development projects and higher net purchases of environmental allowances in 2025 primarily driven by the addition of Energy Harbor.

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Financing Cash Flows

Cash used in financing activities includes:
Nine Months Ended September 30,Increase (Decrease)
20252024
(in millions)
Stock repurchases$(776)$(1,021)$245 
Issuances of debt424 2,200 (1,776)
Repayments/repurchases of debt(764)(2,269)1,505 
Net borrowings (repayments) under the accounts receivable financing facilities475 750 (275)
Dividends paid to common stockholders(229)(230)1 
Dividends paid to preferred stockholders(117)(98)(19)
Dividends paid to noncontrolling interest holders— (15)15 
Tax withholding on stock based compensation(51)(11)(40)
Principal payment on forward repurchase obligation(41)— (41)
TRA Repurchase and tender offer — return of capital— (122)122 
Other financing activity19 (34)53 
Cash used in financing activities$(1,060)$(850)$(210)

The $210 million change was primarily driven by higher net borrowings in the nine months ended September 30, 2024 reflecting amounts borrowed to partially fund the Energy Harbor Merger, partially offset by lower stock repurchases in the nine months ended September 30, 2025.

Available Liquidity

The following table summarizes changes in available liquidity for the nine months ended September 30, 2025:
September 30, 2025December 31, 2024Change
(in millions)
Cash and cash equivalents (a)$602 $1,188 $(586)
Vistra Operations Credit Facilities — Revolving Credit Facility (b)2,459 2,162 297 
Vistra Operations — Commodity-Linked Facility (c)644 771 (127)
Total available liquidity (d)(e)$3,705 $4,121 $(416)
____________
(a)See the condensed consolidated statements of cash flows in the Financial Statements and Cash Flows above for details of the decrease in cash and cash equivalents for the nine months ended September 30, 2025.
(b)The increase in availability for the nine months ended September 30, 2025 was driven by a $297 million decrease in letters of credit outstanding under the facility.
(c)As of September 30, 2025 and December 31, 2024, the borrowing bases were less than the facility limit of $1.75 billion. As of September 30, 2025, available capacity reflects the borrowing base of $644 million and no cash borrowings. As of December 31, 2024, available capacity reflects the borrowing base of $771 million and no cash borrowings.
(d)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 9 to the Financial Statements for additional information.
(e)Excludes any additional letters of credit that may be issued under the Secured LOC Facilities or the Alternative LOC Facilities. See Note 9 to the Financial Statements for additional information.

We believe that we will have access to sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months, including the upcoming payments associated with the acquisition of Nuveen's noncontrolling interest in Vistra Vision. Our operational cash flows tend to be seasonal and weighted toward the second half of the year.

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Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit, Eligible Assets (see Note 8 to the Financial Statements for additional information) and other forms of credit support to satisfy such collateral posting obligations. See Note 9 to the Financial Statements for additional information.

Exchange cleared transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variation margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors, including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. Cash collateral received from counterparties is either used for working capital and other business purposes, including reducing borrowings under credit facilities, or is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties, which would reduce liquidity in the event the cash was not restricted.

As of September 30, 2025, we received or posted cash, letters of credit, and Eligible Assets for commodity hedging and trading activities as follows:

•$1.171 billion in cash and Eligible Assets has been posted with counterparties as compared to $841 million posted as of December 31, 2024;
•$3 million in cash has been received from counterparties as compared to $49 million received as of December 31, 2024;
•$2.400 billion in letters of credit has been posted with counterparties as compared to $2.560 billion posted as of December 31, 2024; and
•$132 million in letters of credit has been received from counterparties as compared to $131 million received as of December 31, 2024

See Collateral Support Obligations below for information related to collateral posted in accordance with the PUCT and ISO/RTO rules.

Income Tax Payments

In the next 12 months, we expect to make approximately $18 million in federal income tax payments, and $94 million in state income tax payments, offset by $13 million in federal income tax refunds and $14 million in state tax refunds. This forecast includes our initial estimate of the impacts of the OBBBA and the Acquisition on cash taxes based on analysis to date.

For the nine months ended September 30, 2025, there were $11 million in federal income tax payments, $70 million in state income tax payments, and no state income tax refunds.

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 September 30, 2025, we were in compliance with the Secured LOC Facilities financial covenants. Although the period ended September 30, 2025 was not a compliance period for the Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement, we would have been in compliance with their respective financial covenants if they were required to be tested at such time. See Note 9 to the Financial Statements for additional information.

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Collateral Support Obligations

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.

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of September 30, 2025, Vistra has posted letters of credit in the amount of $86 million with the PUCT, which is subject to adjustments.

The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $814 million in the form of letters of credit, $81 million in the form of a surety bond and $3 million of cash as of September 30, 2025 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

Material Cross Default/Acceleration Provisions

Certain of our contractual arrangements contain provisions that could result in an event of default if there were a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions.

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greatest of $1.0 billion, 17.5% of Consolidated EBITDA, and 2.5% of Consolidated Total Assets may result in a cross default under the Vistra Operations Credit Facilities and the Commodity-Linked Facility. Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.456 billion and zero, respectively, as of September 30, 2025.

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross-default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness equal to or above a threshold defined in the applicable agreement that results in the acceleration of such debt, would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled.

Under the Vistra Operations Senior Unsecured Indentures, the Vistra Operations Senior Secured Indenture and the Indenture governing the 7.233% Senior Secured Notes (see Note 8 to Vistra's 2024 Form 10-K), a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the 7.233% Senior Secured Notes, and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which may vary by contract.

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The Receivables Facility contains a cross-default provision. The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Dynegy Energy Services Mid-Atlantic, LLC, Ambit Texas, Value Based Brands, Energy Harbor LLC, TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), and Vistra or any of their respective subsidiaries fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, in the case of Vistra Operations, and in a principal amount of at least $50 million, in the case of TXU Energy or any of the other Originators, after the expiration of any applicable grace period, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity. If this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables Facility may be terminated.

The Repurchase Facility contains a cross-default provision. The cross-default provision applies, among other instances, if an event of default (or similar event) occurs under the Receivables Facility or the Vistra Operations Credit Facilities. If this cross-default provision is triggered, a termination event under the Repurchase Facility would occur and the Repurchase Facility may be terminated.

Under the Secured LOC Facilities, a default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of a threshold amount defined in each individual agreement, which threshold amounts range from $300 million to $1 billion, may result in a cross default under the Secured LOC Facilities. In addition, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount in excess of a threshold amount defined in each individual agreement, which threshold amounts range from $300 million to $1 billion, may result in a termination of the Secured LOC Facilities.

Under the Alternative LOC Facilities, a default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greatest of $1.0 billion, 17.5% of Consolidated EBITDA, and 2.5% of Consolidated Total Assets may result in a cross default under the Alternative LOC Facilities. In addition, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount exceeding the threshold above, may result in a termination of the Alternative LOC Facilities.

Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes, the 6.875% Senior Unsecured Notes, the 6.950% Senior Secured Notes, the 6.000% Senior Secured Notes, the 5.050% Senior Secured Notes, and the 5.700% Senior Secured Notes, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 2.75% of total assets and $1.0 billion may result in a cross default under the respective notes and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

A default by Vistra Zero Operating or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greatest of $100 million, 75% of Consolidated EBITDA, and 6% of Consolidated Total Assets may result in a cross default under the Vistra Zero Credit Agreement. Such a default would allow the lenders under such facility to accelerate the maturity of outstanding balances under such facility, which totaled approximately $697 million as of September 30, 2025.

A default by BCOP or any of its subsidiary guarantors in respect of certain provisions defined in the applicable agreement may result in a cross default under the BCOP Credit Agreement. Such a default would allow the lenders under such facility to accelerate the maturity of outstanding balances under such facility. In addition, the interest rate swap agreements that are secured with a lien on BCOP and its subsidiary guarantors' assets on a pari passu basis with the BCOP Credit Agreement contain cross-acceleration provisions, where an event of a default by BCOP or any of its subsidiary guarantors that results in the acceleration of such debt would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with BCOP and require all outstanding obligations under such agreement to be settled.

Under the Nuveen UPA, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the UPA. Such a default would result in the payment obligations under the Nuveen UPA of Vistra Vision Holdings and/or any guarantor thereunder becoming immediately due and payable.
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Guarantees

See Note 13 to the Financial Statements for additional information.

Commitments and Contingencies

See Note 13 to the Financial Statements for additional information.

Changes in Accounting Standards

See Note 1 to the Financial Statements for additional information.

Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In the normal course of business, our financial position is routinely subject to a variety of risks, including market risks associated with (i) changes in commodity prices, (ii) interest rate movements on outstanding debt, and (iii) credit risk, which is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due to us.

Market risks are monitored by our risk management group which operates independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These practices and methodologies measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions. Measurement techniques include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and stress test scenarios. Risk management regularly reports their analysis to the Company's Risk Committee and Executive Committee, and to the Sustainability and Risk Committee of the Board of Directors.

Commodity Price Risk and Oversight

Our business is subject to the inherent risks of market fluctuations in the price of commodities for energy-related products we market or purchase in futures markets including electricity, natural gas, uranium, coal, environmental credits and other energy commodities in competitive wholesale markets. Factors that influence these market fluctuations are dependent upon many factors outside of our control including seasonal changes in supply and demand, weather conditions, market liquidity, governmental, regulatory, and environmental policies.

We manage the commodity price and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management policies. In managing commodity price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices. Our nuclear fleet is eligible for the nuclear PTC provided by the IRA, which provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program.

VaR Methodology

A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities.

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Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level, (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions), and (iii) historical estimates of volatility and correlation data.

The following table summarizes the VaR for Vistra's commodity portfolio based on a 95% confidence level and an assumed holding period of 60 days. Average VaRs are the average of each month-end average for the nine months ended September 30, 2025 and the year ended December 31, 2024, respectively.
Nine Months Ended September 30, 2025Year Ended December 31, 2024
(in millions)
Average VaR
$237 $236 
High VaR
$316 $371 
Low VaR
$138 $86 

Interest Rate Risk

We are exposed to fluctuations in interest rates through our issuance of variable rate debt. We mitigate our exposure to fluctuations in interest rates through entering interest rate swaps. These interest rate swaps limit the impact of interest rate changes on our results of operations and cash flows and lower our overall borrowing costs. Interest rate risk is managed centrally by our treasury function.

As of September 30, 2025, we have approximately $3.9 billion principal amount of variable rate debt consisting of the Vistra Operations Term Loan B-3 Facility, the BCOP Credit Facility and the Vistra Zero Term Loan B Facility (see Note 9 to the Financial Statements for additional information). We have entered into net notional interest rate swaps that will hedge $2.3 billion of our exposure to Vistra Operations variable rate debt through December 2030 and $416 million of our project-level debt through October 2045 (see Note 10 to Financial Statements for additional information). As of September 30, 2025, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $12 million after taking into account the interest rate swaps.

Credit Risk

Our primary concentration of credit risk is associated with the collection of receivables resulting from sales to retail customers and the risk of a counterparty's failure to meet its obligations under derivative contracts. We minimize our exposure to credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial conditions, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 10 to the Financial Statements for additional information.

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Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets (liabilities) arising from commodity contracts and hedging and trading activities totaled $2.718 billion as of September 30, 2025. Including collateral posted to us by counterparties, our net exposure was $2.614 billion, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of September 30, 2025. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.
Exposure Before Credit Collateral
Trade Accounts Receivable
Derivatives
Gross
Exposure
Credit
Collateral		Net
Exposure
(in millions)
Retail segment
$1,978 $(12)$1,966 $48 $1,918 
Texas, East, and Asset Closure segments:
Investment grade$145 $371 $516 $17 $499 
Below investment grade or no rating48 188 236 39 197 
Texas, East, and Asset Closure segments
$193 $559 $752 $56 $696 
Totals$2,171 $547 $2,718 $104 $2,614 

Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements and are excluded from the detail above. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform.

An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us. Significant (i.e., 10% or greater) concentration of credit exposure exists with two counterparties, which represented an aggregate $451 million, or 65%, of our total net exposure of our wholesale segments as of September 30, 2025. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, market role and deemed creditworthiness and the importance of our business relationship with the counterparties.

Item 4.CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) in effect at September 30, 2025. Based on the evaluation performed, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective as of that date.

During the third quarter of 2025, we completed the implementation of a new Enterprise Resource Planning (ERP) system, replacing our previous core financial system. The implementation resulted in significant changes to our processes, procedures, and controls which represents a material change to our internal control over financial reporting (ICFR). Management believes the new ERP system will strengthen our overall control environment. The Company will continue to evaluate and monitor the internal controls over financial reporting during this period of change and will continue to evaluate the operating effectiveness of related key controls. Except for the ERP implementation described above, there were no other changes in our ICFR (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our ICFR.

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PART II. OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS

See Note 13 to the Financial Statements for additional information.

Item 1A.RISK FACTORS

As of the date of this Quarterly Report on Form 10-Q, there have been no material changes to the risk factors discussed in Part I, Item 1A Risk Factors in our 2024 Form 10-K. We could also be affected by additional factors that are not presently known to us or that we currently consider to be immaterial to our operations.

Item 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table provides information about our repurchase of common stock during the three months ended September 30, 2025.
Period
Total Number of Shares PurchasedAverage Price Paid per ShareTotal Number of Shares Purchased as Part of a Publicly Announced ProgramMaximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)
July 1 - July 31, 2025
339,195 $193.22 339,195 $1,372 
August 1 - August 31, 2025
301,735 $199.49 301,735 $1,312 
September 1 - September 30, 2025
314,286 $200.93 314,286 $1,249 
For the quarter ended September 30, 2025
955,216 $197.74 955,216 $1,249 

In October 2021, the Board authorized a share repurchase program (Share Repurchase Program). Under this program, shares of the Company's common stock may be repurchased in open market transactions, privately negotiated transactions, or other means in accordance with federal securities laws. The timing, number, and value of shares repurchased will be determined at our discretion, considering factors such as capital allocation priorities, stock market price, general market and economic conditions, legal requirements, and compliance with debt agreements and preferred stock certificates of designation.
Board Authorization Dates:Amount Authorized for Share Repurchases
(in billions)
October 2021
$2.00 
August 2022
1.25 
March 2023
1.00 
February 2024
1.50 
October 2024
1.00 
Cumulative authorization at September 30, 2025
$6.75 

In October 2025, the Board authorized an incremental amount of $1.0 billion for repurchases under the Share Repurchase Program. We expect to complete repurchases under the Share Repurchase Program by the end of 2027.

See Note 14 to the Financial Statements for additional information.

Item 3.DEFAULTS UPON SENIOR SECURITIES

None.

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Item 4.    MINE SAFETY DISCLOSURES

Vistra currently owns and operates, or is in the process of reclaiming, 12 surface lignite coal mines in Texas to provide fuel for its electricity generation facilities. Vistra also owns or leases, and is in the process of reclaiming, two waste-to-energy surface facilities in Pennsylvania. These mining operations are regulated by the MSHA under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), along with other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects U.S. mines, including Vistra's mines, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders, and proposed assessments are provided in Exhibit 95.1 to this quarterly report on Form 10-Q.

Item 5.OTHER INFORMATION

During the three months ended September 30, 2025, none of our officers or directors adopted or terminated any contract, instruction, or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement".

Item 6.    EXHIBITS

(a)    Exhibits filed or furnished as part of Part II are:
ExhibitsPreviously Filed With File Number*
As
Exhibit
(2)Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2.10001-38086
Form 8-K
(filed March 7, 2023)		2.1—
Transaction Agreement, dated March 6, 2023, by and among Vistra Operations Company LLC, Black Pen Inc. and Energy Harbor Corp.
2.20001-38086
Form 8-K
(filed May 21, 2025)		2.1—
Purchase and Sale Agreement, dated May 15, 2025, by and among Vistra Operations Company LLC, NEP Holdco 1, L.L.C., NatGas Fund Holdings, L.L.C., SEIF III NatGas Holdings, L.L.C. and Edgewater Parent, L.L.C.
(3(i))Articles of Incorporation
3.10001-38086
Form 8-K
(filed May 5, 2025)		3.1—
Amended and Restated Certificate of Incorporation of Vistra Corp.
3.20001-38086
Form 8-K
(filed October 15, 2021)		3.1—
Series A Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on October 14, 2021
3.30001-38086
Form 8-K
(filed December 13, 2021)		3.1—
Series B Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on December 9, 2021
3.40001-38086
Form 8-K
(filed January 4, 2024)		3.1—
Series C Preferred Stock Certificate of Designation filed with the Secretary of State of Delaware on December 29, 2023
(3(ii))By-laws
3.50001-38086
Form 8-K
(filed May 5, 2025)		3.2—
Amended and Restated Bylaws of Vistra Corp., effective May 2, 2025
(4)Instruments Defining the Rights of Security Holders, Including Indentures
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ExhibitsPreviously Filed With File Number*
As
Exhibit
4.1
0001-38086
Form 8-K
(filed July 16, 2025)
4.1
—
Sixteenth Amendment to Receivables Purchase Agreement, dated as of July 11, 2025, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
(10)Material Contracts
10.1
0001-38086
Form 8-K
(filed July 16, 2025)
10.1—
Amendment No. 6 to Master Framework Agreement, dated as of July 11, 2025, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd. as buyer
(31)
Rule 13a-14(a) / 15d-14(a) Certifications
31.1**—
Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2**—
Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32)Section 1350 Certifications
32.1***—
Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2***—
Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(95)Mine Safety Disclosures
95.1**—
Mine Safety Disclosures
XBRL Data Files
101.INS**—
The following financial information from Vistra Corp.'s Quarterly Report on Form 10-Q for the period ended September 30, 2025 formatted in Inline XBRL (Extensible Business Reporting Language) includes: (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Statements of Comprehensive Income (Loss), (iii) the Condensed Consolidated Balance Sheets, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Consolidated Statement of Changes in Equity and (vi) the Notes to the Condensed Consolidated Financial Statements
101.SCH**—XBRL Taxonomy Extension Schema Document
101.CAL**—XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**—XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**—XBRL Taxonomy Extension Label Linkbase Document
101.PRE**—XBRL Taxonomy Extension Presentation Linkbase Document
104**—The Cover Page Interactive Data File does not appear in Exhibit 104 because its XBRL tags are embedded within the Inline XBRL document
____________________
*    Incorporated herein by reference
**    Filed herewith
***    Furnished herewith
82
Table of Contents
SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Vistra Corp.
By:/s/ MARGARET MONTEMAYOR
Name:Margaret Montemayor
Title:Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)

Date: November 6, 2025

83

Source: View Original Filing on SEC EDGAR

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Vistra Corp

NYSE:VST

VST Rankings

#239 Ranked by Market Cap
#2015 Ranked by Dividends

VST Latest News

Nov 7, 2025
TXU Energy Expands its Winter Warmth Program to Support Texans in Need
Nov 6, 2025
Vistra Reports Third Quarter 2025 Results, Narrows 2025 Guidance, and Initiates 2026 Guidance
Sep 11, 2024
Vistra Partners With Sunrun on Residential Battery Aggregation Program
Oct 30, 2025
Vistra Declares Dividend on Common Stock, Series B Preferred Stock, and Series C Preferred Stock
Oct 22, 2025
Lotus Infrastructure Partners Announces Closing of Natural Gas Portfolio to Vistra Corp.

VST Latest SEC Filings

Nov 6, 2025
[8-K] Vistra Corp. Reports Material Event
Oct 31, 2025
[Form 4] Vistra Corp. Insider Trading Activity
Oct 29, 2025
[Form 4] Vistra Corp. Insider Trading Activity
Oct 29, 2025
[144] Vistra Corp. SEC Filing
Oct 28, 2025
[8-K] Vistra Corp. Reports Material Event

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93.03%
2.18%
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